Abstract:
Estimates of global total “liquid” hydrocarbon resources are dominated by structures known as oil sands or tar sands which represent approximately two-thirds of the total recoverable resources. This is despite the Canadian Athabasca Oil Sands, which dominate these oil sand based reserves at 1.7 trillion barrels, are calculated at only 10% recovery rate. However, irrespective of whether it is the 3.6 trillion barrels recoverable from the oil sands or the 1.75 trillion barrels from conventional oil reservoirs worldwide, it is evident that significant financial return and extension of the time oil is available to the world arise from increasing the recoverable percentage of such resources. According to embodiments of the invention pressure differentials are exploited to advance production of wells, adjust the evolution of the depletion chambers formed laterally between laterally spaced wells to increase the oil recovery percentage, and provide recovery in deeper reservoirs.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This patent application claims the benefit of U.S. Provisional Patent Application 61/487,770 filed May 19, 2011 entitled “Pressure Assisted Oil Recovery.” 
    
    
     FIELD OF THE INVENTION 
     This invention relates to oil recovery and more specifically to exploiting pressure in oil recovery. 
     BACKGROUND OF THE INVENTION 
     Over the last two centuries, advances in technology have made our civilization completely oil, gas &amp; coal dependent. Whilst gas and coal are primarily use for fuel oil is different in that immense varieties of products are and can be derived from it. A “brief” list of some of these products includes gasoline, diesel, fuel oil, propane, ethane, kerosene, liquid petroleum gas, lubricants, asphalt, bitumen, cosmetics, petroleum jelly, perfume, dish-washing liquids, ink, bubble gums, car tires, etc. In addition to these oil is the source of the starting materials for most plastics that form the basis of a massive number of consumer and industrial products. 
     Table 1 below lists the top 15 consuming nations based upon 2008 data in terms of thousands of barrels (bbl) and thousand of cubic meters per day.  FIG. 1A  presents the geographical distribution of consumption globally. 
     
       
         
               
             
               
               
               
               
             
               
               
               
               
             
           
               
                 TABLE 1 
               
             
             
               
                   
               
               
                 2008 Oil Consumption for Top 15 Consuming Nations 
               
             
          
           
               
                   
                 Nation 
                 (1000 bbl/day) 
                 (1000 m 3 /day)            
               
               
                   
                   
               
             
          
           
               
                 1 
                 United States 
                 19,497.95 
                 3,099.9 
               
               
                 2 
                 China 
                 7,831.00 
                 1,245.0 
               
               
                 3 
                 Japan 
                 4,784.85 
                 760.7 
               
               
                 4 
                 India 
                 2,962.00 
                 470.9 
               
               
                 5 
                 Russia 
                 2,916.00 
                 463.6 
               
               
                 6 
                 Germany 
                 2,569.28 
                 408.5 
               
               
                 7 
                 Brazil 
                 2,485.00 
                 395.1 
               
               
                 8 
                 Saudi Arabia 
                 2,376.00 
                 377.8 
               
               
                 9 
                 Canada 
                 2,261.36 
                 359.5 
               
               
                 10 
                 South Korea 
                 2,174.91 
                 345.8 
               
               
                 11 
                 Mexico 
                 2,128.46 
                 338.4 
               
               
                 12 
                 France 
                 1,986.26 
                 315.8 
               
               
                 13 
                 Iran (OPEC) 
                 1,741.00 
                 276.8 
               
               
                 14 
                 United Kingdom 
                 1,709.66 
                 271.8 
               
               
                 15 
                 Italy 
                 1,639.01 
                 260.6 
               
               
                   
               
             
          
         
       
     
     In terms of oil production Table 1B below lists the top 15 oil producing nations and the geographical distribution worldwide is shown in  FIG. 1B . Comparing Table 1A and Table 1B shows how some countries like Japan are essentially completely dependent on oil imports whilst most other countries such as the United States in the list whilst producing significantly are still massive importers. Very few countries, such as Saudi Arabia and Iran are net exporters of oil globally. 
     
       
         
               
             
               
               
               
               
             
               
               
               
               
             
           
               
                 TABLE 2 
               
             
             
               
                   
               
               
                 Top 15 Oil Producing Nations 
               
             
          
           
               
                   
                 Nation 
                 (1000 bbl/day) 
                 Market Share 
               
               
                   
                   
               
             
          
           
               
                 1 
                 Saudi Arabia 
                 9,760 
                 11.8% 
               
               
                 2 
                 Russia 
                 9,934 
                 12.0% 
               
               
                 3 
                 United States 
                 9,141 
                 11.1% 
               
               
                 4 
                 Iran (OPEC) 
                 4,177 
                 5.1% 
               
               
                 5 
                 China 
                 3,996 
                 4.8% 
               
               
                 6 
                 Canada 
                 3,294 
                 4.0% 
               
               
                 7 
                 Mexico 
                 3,001 
                 3.6% 
               
               
                 8 
                 UAE (OPEC) 
                 2,795 
                 3.4% 
               
               
                 9 
                 Kuwait (OPEC) 
                 2,496 
                 3.0% 
               
               
                 10 
                 Venezuela (OPEC) 
                 2,471 
                 3.0% 
               
               
                 11 
                 Norway 
                 2,350 
                 2.8% 
               
               
                 12 
                 Brazil 
                 2,577 
                 3.1% 
               
               
                 13 
                 Iraq (OPEC) 
                 2,400 
                 2.9% 
               
               
                 14 
                 Algeria (OPEC) 
                 2,126 
                 2.6% 
               
               
                 15 
                 Nigeria (OPEC) 
                 2,211 
                 2.7% 
               
               
                   
               
             
          
         
       
     
     In terms of oil reserves then these are dominated by a relatively small number of nations as shown below in Table 3 and in  FIG. 1C . With the exception of Canada the vast majority of these oil reserves are associated with conventional oil fields. Canadian reserves being dominated by Athabasca oil sands which are large deposits of bitumen, or extremely heavy crude oil, located in northeastern Alberta, Canada. The stated reserves of approximately 170,000 billion barrels are based upon only 10% of total actual reserves, these being those economically viable to recover in 2006. 
     
       
         
               
             
               
               
               
               
             
               
               
               
               
             
           
               
                 TABLE 3 
               
             
             
               
                   
               
               
                 Top 15 Oil Reserve Nations 
               
             
          
           
               
                   
                 Nation 
                 Reserves (1000 bbl) 
                 Share 
               
               
                   
                   
               
             
          
           
               
                 1 
                 Saudi Arabia 
                 264,600,000 
                 19.00% 
               
               
                 2 
                 Canada 
                 175,200,000 
                 12.58% 
               
               
                 3 
                 Iran 
                 137,600,000 
                 9.88% 
               
               
                 4 
                 Iraq 
                 115,000,000 
                 8.26% 
               
               
                 5 
                 Kuwait 
                 104,000,000 
                 7.47% 
               
               
                 6 
                 United Arab Emirates 
                 97,800,000 
                 7.02% 
               
               
                 7 
                 Venezuela 
                 97,770,000 
                 7.02% 
               
               
                 8 
                 Russia 
                 74,200,000 
                 5.33% 
               
               
                 9 
                 Libya 
                 47,000,000 
                 3.38% 
               
               
                 10 
                 Nigeria 
                 37,500,000 
                 2.69% 
               
               
                 11 
                 Kazakhstan 
                 30,000,000 
                 2.15% 
               
               
                 12 
                 Qatar 
                 25,410,000 
                 1.82% 
               
               
                 13 
                 China 
                 20,350,000 
                 1.46% 
               
               
                 14 
                 United States 
                 19,120,000 
                 1.37% 
               
               
                 15 
                 Angola 
                 13,500,000 
                 0.97% 
               
               
                   
               
             
          
         
       
     
     Therefore in the vast majority of wells are drilled into oil reservoirs to extract the crude oil. An oil well is created by drilling a hole 5 to 50 inches (127.0 mm to 914.4 mm) in diameter into the earth with a drilling rig that rotates a drill string with a bit attached. After the hole is drilled, sections of steel pipe (casing), slightly smaller in diameter than the borehole, are placed in the hole. Cement may be placed between the outside of the casing and the borehole to provide structural integrity and to isolate high pressure zones from each other and from the surface. With these zones safely isolated and the formation protected by the casing, the well can be drilled deeper, into potentially more unstable formations, with a smaller bit, and also cased with a smaller size casing. Typically wells have two to five sets of subsequently smaller hole sizes drilled inside one another, each cemented with casing. 
     Oil recovery operations from conventional oil wells have been traditionally subdivided into three stages: primary, secondary, and tertiary. Primary production, the first stage of production, produces due to the natural drive mechanism existing in a reservoir. These “Natural lift” production methods that rely on the natural reservoir pressure to force the oil to the surface are usually sufficient for a while after reservoirs are first tapped. In some reservoirs, such as in the Middle East, the natural pressure is sufficient over a long time. The natural pressure in many reservoirs, however, eventually dissipates such that the oil must then be pumped out using “artificial lift” created by mechanical pumps powered by gas or electricity. Over time, these “primary” methods become less effective and “secondary” production methods may be used. 
     The second stage of oil production, secondary recovery, is usually implemented after primary production has declined to unproductive levels, usually defined in economic return rather than absolute oil flow. Traditional secondary recovery processes are water flooding, pressure maintenance, and gas injection, although the term secondary recovery is now almost synonymous with water flooding. Tertiary recovery, the third stage of production, commonly referred to as enhanced oil recovery (“EOR”) is implemented after water flooding. Tertiary processes use miscible and/or immiscible gases, polymers, chemicals, and thermal energy to displace additional oil after the secondary recovery process becomes uneconomical. 
     Enhanced oil recovery processes can be classified into four overall categories: mobility control, chemical, miscible, and thermal.
         Mobility-control processes, as the name implies, are those based primarily on maintaining a favorable mobility ratio. Examples of mobility control processes are thickening of water with polymers and reducing gas mobility with foams.   Chemical processes are those in which certain chemicals, such as surfactants or alkaline agents, are injected to utilize interfacial tension reduction, leading to improved displacement of oil.   In miscible processes, the objective is to inject fluids that are directly miscible with the oil or that generate miscibility in the reservoir through composition alteration. The most popular form of a miscible process is the injection of carbon dioxide.   Thermal processes rely on the injection of thermal energy or the in-situ generation of heat to improve oil recovery by reducing the viscosity of oil.       

     In the United States, primary production methods account for less than 40% of the oil produced on a daily basis, secondary methods account for about half, and tertiary recovery the remaining 10%. 
     Bituminous sands, colloquially known as oil sands or tar sands, are a type of unconventional petroleum deposit. The oil sands contain naturally occurring mixtures of sand, clay, water, and a dense and extremely viscous form of petroleum technically referred to as bitumen (or colloquially “tar” due to its similar appearance, odour, and colour). These oil sands reserves have only recently been considered as part of the world&#39;s oil reserves, as higher oil prices and new technology enable them to be profitably extracted and upgraded to usable products. They are often referred to as unconventional oil or crude bitumen, in order to distinguish the bitumen extracted from oil sands from the free-flowing hydrocarbon mixtures known as crude oil 
     Many countries in the world have large deposits of oil sands, including the United States, Russia, and various countries in the Middle East. However, the world&#39;s largest deposits occur in two countries: Canada and Venezuela, each of which has oil sand reserves approximately equal to the world&#39;s total reserves of conventional crude oil. As a result of the development of Canadian oil sands reserves, 44% of Canadian oil production in 2007 was from oil sands, with an additional 18% being heavy crude oil, while light oil and condensate had declined to 38% of the total. 
     Because growth of oil sands production has exceeded declines in conventional crude oil production, Canada has become the largest supplier of oil and refined products to the United States, ahead of Saudi Arabia and Mexico. Venezuelan production is also very large, but due to political problems within its national oil company, estimates of its production data are not reliable. Outside analysts believe Venezuela&#39;s oil production has declined in recent years, though there is much debate on whether this decline is depletion-related or not. 
     However, irrespective of such issues the oil sands may represent as much as two-thirds of the world&#39;s total “liquid” hydrocarbon resource, with at least 1.7 trillion barrels (270×10 9  m 3 ) in the Canadian Athabasca Oil Sands alone assuming even only a 10% recovery rate. In Oct. 2009, the United States Geological Service updated the Orinoco oil sands (Venezuela) mean estimated recoverable value to 513 billion barrels (81.6×10 9  m 3 ) making it “one of the world&#39;s largest recoverable” oil deposits. Overall the Canadian and Venezuelan deposits contain about 3.6 trillion barrels (570×10 9  m 3 ) of recoverable oil, compared to 1.75 trillion barrels (280×10 9  m 3 ) of conventional oil worldwide, most of it in Saudi Arabia and other Middle-Eastern countries. 
     Because extra-heavy oil and bitumen flow very slowly, if at all, toward producing wells under normal reservoir conditions, the oil sands must be extracted by strip mining and processed or the oil made to flow into wells by in situ techniques, which reduce the viscosity. Such in situ techniques include injecting steam, solvents, heating the deposit, and/or injecting hot air into the oil sands. These processes can use more water and require larger amounts of energy than conventional oil extraction, although many conventional oil fields also require large amounts of water and energy to achieve good rates of production. Accordingly, these oil sand deposits were previously considered unviable until the 1990s when substantial investment was made into them as oil prices increased to the point of economic viability as well as concerns over security of supply, long term global supply, etc. 
     Amongst the reasons for more water and energy of oil sand recovery apart from the initial energy expenditure in reducing viscosity is that the heavy crude feedstock recovered requires pre-processing before it is fit for conventional oil refineries. This pre-processing is called ‘upgrading’, the key components of which are:
         1. removal of water, sand, physical waste, and lighter products;   2. catalytic purification by hydrodemetallisation (HDM), hydrodesulfurization (HDS) and hydrodenitrogenation (HDN); and   3. hydrogenation through carbon rejection or catalytic hydrocracking (HCR).       

     As carbon rejection is very inefficient and wasteful in most cases, catalytic hydrocracking is preferred in most cases. All these processes take large amounts of energy and water, while emitting more carbon dioxide than conventional oil. 
     Amongst the category of known secondary production techniques the injection of a fluid (gas or liquid) into a formation through a vertical or horizontal injection well to drive hydrocarbons out through a vertical or horizontal production well. Steam is a particular fluid that has been used. Solvents and other fluids (e.g., water, carbon dioxide, nitrogen, propane and methane) have also been used. These fluids typically have been used in either a continuous injection and production process or a cyclic injection and production process. The injected fluid can provide a driving force to push hydrocarbons through the formation, or the injected fluid can enhance the mobility of the hydrocarbons (e.g., by reducing viscosity via heating) thereby facilitating the release of the more mobile hydrocarbons to a production location. Recent developments using horizontal wells have focused on utilizing gravity drainage to achieve better results. At some point in a process using separate injection and production wells, the injected fluid may migrate through the formation from the injection well to the production well thereby “contaminating” the oil recovered in the sense that additional processing must be applied before the oil can be pre-processed for compatibility with convention oil refineries working with the light oil recovered from conventional oil well approaches. 
     Therefore, a secondary production technique injecting a selected fluid and for producing hydrocarbons should maximize production of the hydrocarbons with a minimum production of the injected fluid, see for example U.S. Pat. No. 4,368,781. Accordingly, the early breakthrough of the injected fluid from an injection well to a production well and an excessive rate of production of the injected fluid is not desirable. See for example Joshi et al in “Laboratory Studies of Thermally Aided Gravity Drainage Using Horizontal Wells” (AOSTRA J. of Research, pages 11-19, vol. 2, no. 1, 1985). It has also been disclosed that optimum production from a horizontal production well is limited by the critical velocity of the fluid through the formation. This being thought necessary to avoid so-called “fingering” of the injected fluid through the formation, see U.S. Pat. No. 4,653,583, although in U.S. Pat. No. 4,257,650 it is disclosed that “fingering” is not critical in radial horizontal well production systems. 
     The foregoing disclosures have been within contexts referring to various spatial arrangements of injection and production wells, which can be classified as follows: vertical injection wells with vertical production wells, horizontal injection wells with horizontal production wells, and combinations of horizontal and vertical injection and production wells. Whilst embodiments of the invention described below can be employed in all of these configurations the dominant production methodology today relates to the methods using separate, discrete horizontal injection and production wells. This arises due to the geological features of oil sands wherein the oil bearing are typically thin but distributed over a large area. Amongst the earliest prior art for horizontal injection wells with horizontal production well arrangements are U.S. Pat. Nos. 4,700,779; 4,385,662; and 4,510,997. 
     Within the initial deployments the parallel horizontal injection and production wells vertically were aligned a few meters apart as disclosed in the aforementioned article by Joshi. Associated articles include:
         Butler et al in “The gravity drainage of steam-heated heavy oil to parallel horizontal wells” (J. of Canadian Petroleum Technology, pages 90-96, 1981);   Butler in “Rise of interfering steam chambers” (J. of Canadian Petroleum Technology, pages 70-75, vol. 26, no. 3, 1986);   Ferguson et al in “Steam-assisted gravity drainage model incorporating energy recovery from a cooling steam chamber” (J. of Canadian Petroleum Technology, pages 75-83, vol. 27, no. 5, 1988);   Butler et al in “Theoretical Estimation of Breakthrough Time and Instantaneous Shape of Steam Front During Vertical Steamflooding,” (AOSTRA J. of Research, pages 359-381, vol. 5, no. 4, 1989); and   Griffin et al in “Laboratory Studies of the Steam-Assisted Gravity Drainage Process,” (5 th  Advances in Petroleum Recovery &amp; Upgrading Technology Conference, June 1984, Calgary, Alberta, Canada (session 1, paper 1).       

     Vertically aligned horizontal wells are also disclosed in U.S. Pat. Nos. 4,577,691; 4,633,948; and 4,834,179. Staggered horizontal injection and production wells, wherein the injection and production wells are both laterally and vertically spaced from each other, are disclosed in Joshi in “A Review of Thermal Oil Recovery Using Horizontal Wells” (In Situ, Vol. 11, pp 211-259, 1987); Change et al in “Performance of Horizontal-Vertical Well Combinations for Steamflooding Bottom Water Formations,” (CIM/SPE 90-86, Petroleum Society of CIM/Society of Petroleum Engineers) as well as U.S. Pat. Nos. 4,598,770 and 4,522,260. 
     Amongst other patents addressing such recovery processes are U.S. Pat. Nos. 5,456,315&#39; 5,860,475; 6,158,510; 6,257,334; 7,069,990; 6,988,549; 7,556,099; 7,591,311 and US Patent Applications 2006/0,207,799; 2008/0,073,079; 2010/0,163,229, 2009/0,020,335; 2008/0,087,422; 2009/0,255,661; 2009/0,260,878; 2009/0,260,878; 2008/0,289,822; 2009/0,044,940; 2009/0,288,827; and 2010/0,326,656. Additionally there are literally hundreds of patents relating to the steam generating apparatus, drilling techniques, sensors, etc associated with such production techniques as well as those addressing combustion assisted gravity drainage etc. 
     The first commercially applied process was cyclic steam stimulation, commonly referred to as “huff and puff”, wherein steam is injected into the formation, commonly at above fracture pressure, through a usually vertical well for a period of time. The well is then shut in for several months, referred to as the “soak” period, before being re-opened to produce heated oil and steam condensate until the production rate declines. The entire cycle is then repeated and during the course of the process an expanding “steam chamber” is gradually developed where the oil has drained from the void spaces of the chamber, been produced through the well during the production phase, and is replaced with steam. Newly injected steam moves through the void spaces of the hot chamber to its boundary, to supply heat to the cold oil at the boundary. 
     However, there are problems associated with the cyclic process including:
         fracturing tends to occur vertically along a direction dictated by the tectonic regime present in the formation;   steam tends to preferentially move through the fractures and heat outwardly therefrom so that developed chamber tends to be relatively narrow;   low efficiency with respect to steam utilization; and   there are large bodies of unheated oil left in the zone extending between adjacent wells with their linearly extending steam chambers.       

     Accordingly, the cyclic process relatively low oil recovery. As such, as described in Canadian Patent 1,304,287, a continuous steam process has become dominant approach, known as steam-assisted gravity drainage (“SAGD”). The approach exploiting:
         a pair of coextensive horizontal wells, one above the other, located close to the base of the formation;   the formation between the wells is heated by circulating steam through each of the wells at the same time to create a pair of “hot fingers”;   when the oil is sufficiently heated so that it may be displaced or driven from one well to the other, fluid communication between the wells is established and steam circulation through the wells is terminated;   steam injection below the fracture pressure is initiated through the upper well and the lower well opened to produce draining liquid; and   the production well is throttled to maintain steam trap conditions and to keep the temperature of the produced liquid at about 6-10° C. below the saturation steam temperature at the production well.       

     This ensures a short column of liquid is maintained over the production well, thereby preventing steam from short-circuiting into the production well. As the steam is injected, it rises and contacts cold oil immediately above the upper injection well. The steam gives up heat and condenses; the oil absorbs heat and becomes mobile as its viscosity is reduced. The condensate and heated oil drain downwardly under the influence of gravity. The heat exchange occurs at the surface of an upwardly enlarging steam chamber extending up from the wells. This chamber being constituted of depleted, porous, permeable sand from which the oil has largely drained and been replaced by steam. 
     The steam chamber continues to expand upwardly and laterally until it contacts the overlying impermeable overburden and has an essentially triangular cross-section. If two laterally spaced pairs of wells undergoing SAGD are provided, their steam chambers grow laterally until they contact high in the reservoir. At this stage, further steam injection is terminated and production declines until the wells are abandoned. The SAGD process is characterized by several advantages, including relatively low pressure injection so that fracturing is not likely to occur, steam trap control minimizes short-circuiting of steam into the production well, and the SAGD steam chambers are broader than those developed by the cyclic process. 
     As a result oil recovery is generally better and with reduced energy consumption and emissions of greenhouse gases. However, there are still limitations with the SAGD process which need addressing. These include the need to more quickly achieve production from the SAGD wells, the need to heat the formation laterally between laterally spaced wells to increase the oil recovery percentage; and provide SAGD operating over deeper oil sand formations. 
     In SAGD the velocity of bitumen falling through a column of porous media having equal pressures at top and bottom can be calculated from Darcy&#39;s Law, see Equation 1. 
                     U   O   q     =         k   O     ⁢     P   O     ⁢     g   O         μ   O               (   1   )               
where k O  is the effective permeability to bitumen and μ O  is the viscosity of the bitumen. For Athabasca bitumen at about 200° C. and using 5 as the value Darcy&#39;s effective permeability, the resulting velocity will be about 40 cm/day. Extending this to include a pressure differential then the equation for the flow velocity becomes that given by Equation 2.
 
               U   O   +     =           k   O     ⁢     P   O     ⁢   g       μ   O       +         k   O     ⁢   Δ   ⁢           ⁢   P         μ   O     ⁢   L               
where ΔP is the pressure differential between the two well bores and L is the interwell bore separation. For a typical interwell spacing this results in the value given in Table 1 below.
 
     
       
         
               
             
               
               
               
               
               
             
               
               
               
               
               
             
           
               
                 TABLE 1 
               
             
             
               
                   
               
               
                 Increased Bitumen Velocity under Pressure Differential 
               
             
          
           
               
                   
                 k o Δ/μ o L 
                 k o P o g/μ o  = U o q 
                 U o   +   
                   
               
               
                 ΔP (psia) 
                 (cm/day) 
                 (cm/day) 
                 (cm/day) 
                 U o   +/U   o g 
               
               
                   
               
             
          
           
               
                 0.00 
                 0.000 
                 39.4 
                 39.4 
                 1.00 
               
               
                 0.01 
                 0.046 
                 39.4 
                 39.5 
                 1.00 
               
               
                 0.10 
                 0.427 
                 39.4 
                 39.9 
                 1.01 
               
               
                 1.00 
                 4.410 
                 39.4 
                 43.8 
                 1.11 
               
               
                 10.00 
                 44.200 
                 39.4 
                 83.6 
                 2.12 
               
               
                 50.00 
                 220.8 
                 39.4 
                 260.0 
                 6.60 
               
               
                   
               
             
          
         
       
     
     It is evident from the data presented in Table 1 that a pressure differential can substantially increase the mobility of the heavy oil in oil sand deposits. Considering the Athabasca oil sands about 20 percent of the reserves are recoverable by surface mining where the overburden is less than 75 m (250 feet). It is the remaining 80 percent of the oil sands that are buried at a depth of greater than 75 m where SAGD and other in-situ technologies apply. Typically, pressure increases at an average rate of approximately 0.44 psi per foot underground, such that the pressure at 250 feet is 110 psi higher than at the surface, at 350 feet it is 154 psi higher. For comparison atmospheric pressure is approximately 14.7 psi, such that the pressure at 350 feet is approximately 10 atmospheres. 
     Accordingly, the inventor has established that beneficially pressure differentials may be exploited to advance production from SAGD wells by increasing the velocity of heavy oils, that pressure differentials may be exploited to adjust the evolution of the steam chambers formed laterally between laterally spaced wells to increase the oil recovery percentage, and provide SAGD operating over deeper oil sand formations. 
     SUMMARY OF THE INVENTION 
     It is an object of the present invention to enhance second stage oil recovery and more specifically to exploiting pressure in oil recovery. 
     In accordance with an embodiment of the invention there is provided a method comprising:
     providing first and second well pairs separated by a first predetermined separation, each well
       pair comprising:   a first well within an oil bearing structure; and   a second well within the oil bearing structure at a first predetermined vertical offset to the first well, substantially parallel to the first well and a first predetermined lateral offset to the first well;   
       providing a third well within the oil bearing structure at a predetermined location between the first and second well pairs;   selectively injecting a first fluid into the first well of each well pair according to a first predetermined schedule under first predetermined conditions to create a zone of increased mobility within the oil bearing structure; and   generating a large singular zone of increased mobility by selectively injecting a second fluid into the third well according to a second predetermined schedule under second predetermined conditions at least one of absent and prior to any communication between the zones of increased mobility.   

     In accordance with an embodiment of the invention there is provided providing first and second well pairs separated by a first predetermined separation, each well pair comprising:
         providing a first well within an oil bearing structure having a predetermined substantially non-parallel relationship to a second well; and   the second well within the oil bearing structure having a predetermined portion of the second well at a first predetermined vertical offset and a first predetermined lateral offset to a predetermined portion of the first well;       providing a third well within the oil bearing structure at a predetermined location between the first and second well pairs;   selectively injecting a first fluid into the first well of each well pair according to a first predetermined schedule under first predetermined conditions to create a zone of increased mobility within the oil bearing structure; and   generating a large singular zone of increased mobility by selectively injecting a second fluid into the third well according to a second predetermined schedule under second predetermined conditions at least one of absent and prior to any communication between the zones of increased mobility.   

     Other aspects and features of the present invention will become apparent to those ordinarily skilled in the art upon review of the following description of specific embodiments of the invention in conjunction with the accompanying figures. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Embodiments of the present invention will now be described, by way of example only, with reference to the attached Figures, wherein: 
         FIG. 1A  depicts the geographical distribution of consumption globally; 
         FIG. 1B  depicts the geographical distribution worldwide of oil production; 
         FIG. 1C  depicts the geographical distribution worldwide of oil reserves; 
         FIG. 2  depicts a secondary oil recovery well structure according to the prior art of Jones in U.S. Pat. No. 5,080,172; 
         FIGS. 3A and 3B  depict outflow control devices according to the prior art of Forbes in US Patent Application 2008/0,251,255 for injecting fluid into an oil bearing structure; 
         FIGS. 4A and 4B  depict a SAGD process according to the prior art of Cyr et al in U.S. Pat. No. 6,257,334; 
         FIG. 4C  depicts the relative permeability of oil-water and liquid gas employed in the simulations of prior art SAGD and SAGD according to embodiments of the invention together with bitumen viscosity; 
         FIGS. 4D and 4E  depict simulation results for a SAGD process according to the prior art showing depletion and isolation of each SAGD well-pair; 
         FIG. 5A  depicts a CSS-SAGD oil recovery scenario according to the prior art of Coskuner in US Patent Application 2009/0,288,827; 
         FIG. 5B  depicts a SAGD oil recovery scenario according to the prior art Arthurs et al in U.S. Pat. No. 7,556,099; 
         FIG. 6  depicts an oil recovery scenario and well structure according to an embodiment of the invention; 
         FIGS. 7A and 7B  depict oil recovery scenarios and well structure according to an embodiment of the invention; 
         FIG. 8  depicts an oil recovery scenario and well structure according to an embodiment of the invention; 
         FIG. 9  depicts an oil recovery scenario and well structure according to an embodiment of the invention; 
         FIG. 10  depicts an oil recovery scenario and well structure according to an embodiment of the invention; 
         FIG. 11  depicts an oil recovery scenario and well structure according to an embodiment of the invention; 
         FIG. 12  depicts an oil recovery scenario and well structure according an embodiment of the invention; 
         FIG. 13  depicts an oil recovery scenario and well structure according an embodiment of the invention; 
         FIG. 14  depicts an oil recovery scenario and well structure according an embodiment of the invention; 
         FIG. 15  depicts an oil recovery well structure according to an embodiment of the invention; 
         FIGS. 16A and 16B  depict simulation results for a pressure assisted oil recovery process according to an embodiment of the invention with primary injectors within SAGD well pairs operated at a lower pressure than intermediate wells acting as secondary injectors; 
         FIGS. 17A and 17B  depict simulation results for a pressure assisted oil recovery process according to an embodiment of the invention with primary injectors within SAGD well pairs operated at a lower pressure than intermediate wells acting as secondary injectors; 
         FIGS. 18A and 18B  depict simulation results for a pressure assisted oil recovery process according to an embodiment of the invention with primary injectors within SAGD well pairs operated at a lower pressure than intermediate wells acting as secondary injectors with delayed injection; 
         FIGS. 19A and 19B  depict simulation results for a pressure assisted oil recovery process according to an embodiment of the invention with primary injectors within SAGD well pairs operated at the same 1800 kPa as intermediate wells acting as secondary injectors; 
         FIGS. 20A and 20B  depict simulation results for a pressure assisted oil recovery process according to an embodiment of the invention with primary injectors within SAGD well pairs operated at the same 2000 kPa pressure as intermediate wells acting as secondary injectors; 
         FIGS. 21A and 21B  depict simulation results for a pressure assisted oil recovery process according to an embodiment of the invention with primary injectors within SAGD well pairs operated at a lower pressure than intermediate wells acting as secondary injectors with reduced spacing of 37.5 m; 
         FIG. 22  depicts oil recovery scenarios and well structures according to embodiments of the invention; 
         FIGS. 23A and 23B  depict simulation results for a pressure assisted oil recovery process according to an embodiment of the invention with horizontally disposed SAGD well pairs operating with injectors at lower pressure than laterally disposed intermediate wells such as depicted in  FIG. 22 ; and 
         FIGS. 24A and 24B  depict simulation results for a pressure assisted oil recovery process according to an embodiment of the invention with standard SAGD well pairs operating at lower pressure than additional injector wells laterally disposed to the SAGD well pairs. 
         FIGS. 25-26  show top views of non-parallel well configurations. In both these configurations, the injector wells ( 2510  and  2610 ) are vertically spaced in a non-parallel relationship from the lower producer wells ( 2520  and  2620 ) with the secondary wells ( 2530  and  2630 ) laterally offset to both. 
     
    
    
     DETAILED DESCRIPTION 
     The present invention is directed to second stage oil recovery and more specifically to exploiting pressure in oil recovery. 
     Referring to  FIG. 2  there is depicted a secondary oil recovery well structure according to the prior art of Jones in U.S. Pat. No. 5,080,172 entitled “Method of Recovering Oil Using Continuous Steam Flood from a Single Vertical Wellbore.” Accordingly there is illustrated a relatively thick subterranean, viscous oil-containing formation  10  penetrated by well  12 . The well  12  has a casing  14  set below the oil-containing formation  10  and in fluid communication with the full vertical thickness of the formation  10  by means of perforations. Injection tubing  16  is positioned coaxially inside the casing  14  forming an annular space  17 . Injection tubing  16  extends near the bottom of the formation  10  and is in fluid communication with that portion of the annulus  17  adjacent to the full vertical thickness of the formation by means of perforations as shown in  FIG. 2A  or is in fluid communication with the lower portion of the annulus  17  by an opening at its lower end. Production tubing  18  passes downwardly through injection tubing  18  forming an annular space  20  between injection tubing  16  and production tubing  18 . Production tubing  18  extends to a point adjacent the bottom, i.e., at the bottom or slightly above or below the bottom, or below the bottom of the oil-containing formation  10 , preferably 10 feet or less, and may be perforated in the lower portion to establish fluid flow communication with the lower portion of the formation  10  as shown in  FIG. 2A . 
     Production tubing  18  is axially aligned inside injection tubing  16 . In another embodiment the lower end of tubing may simply be open to establish fluid communication with the lower portion of the formation  10 . Production tubing  18  can be fixed in the wellbore or preferably provided with means to progressively withdraw or lower the production tubing inside the wellbore to obtain improved steam-oil ratios and/or higher oil production rates. If desirable, the well casing  14  is insulated to about the top of the oil-containing formation  10  to minimize heat losses. 
     In the first phase, steam is injected into the oil-containing formation  10  via the annular space  20  between injection tubing  16  and production tubing  18  until the oil-containing formation  10  around the casing  14  becomes warm and the pressure in the formation is raised to a predetermined value. The injected steam releases heat to the formation and the oil resulting in a reduction in the viscosity of the oil and facilitating its flow by gravitational forces toward the bottom of the formation where it is recovered along with condensation water via production tubing  18 . Production flow rate restriction may be accomplished by use of a choke or a partially closed throttling valve. 
     As discussed supra SAGD and pressure assisted oil recovery according to embodiments of the invention employ an injection well bore and a production well bore. In VASSOR as described below in respect of  FIGS. 6 to 13  an additional bore may be disposed alongside the injection and production well bores or the production well bore may operate during predetermined periods as the pressure bore. Disposed within the production well bore is outflow control device  61  according to the prior art of Forbes in US Patent Application 2008/0,251,255 as shown in  FIG. 3A . 
     Inflow control device  61  as shown comprises a housing  61   a , formed on tubing  60 , which is resident in steam injection pipe string apparatus. Steam may be directed through opening  62  in tubular member  60  and then through orifice  63  and into the injection wellbore. Orifice  63  may, for example, comprise a nozzle. Referring to  FIG. 3B  there is shown an inflow control device  90  which is utilized with sand screen apparatus  91 . An opening  92  is formed in base pipe  93  to permit the flow of steam through nozzle  94  and into the steam injection wellbore via sand screen apparatus  91 . The inflow control device  90  utilizes a plurality of C-type metal seals  95 . An example of a sand screen for such inflow control device is presented in US Patent Application 2006/0,048,942. 
     In accordance with the present invention, a steam injection pipe string apparatus according may further comprise Distributed Temperature Sensing (DST) apparatus. Such DST apparatus advantageously utilizes fiber optic cables containing sensors to sense the temperature changes along the length of the injection apparatus and may, for example, provide information from which adjustments to the steam injection process are derived. 
     Now referring to  FIG. 4A  there is depicted there are depicted SAGD process cross-sections according to the prior art wherein a pair of groups of wells are viewed in cross-section according to standard process  400  and advanced process  450  according to the prior art of Cyr et al in U.S. Pat. No. 6,257,334. Accordingly in each case there are shown a pair of wells  14 , consisting of an upper steam injection well and lower production well. These are disposed to the bottom of the oil sand layer  10 . This oil sand layer  10  being disposed beneath rock overburden  12  that extends to the surface  18 . In standard process  14  the SAGD process at maturity results in steam chambers  16  which are disconnected within the oil sand layer and generally triangular in cross-section but specific conditions within the oil sand layer  10  may means that oil  20  is not recovered in the same manner from one pair of wells (right hand side) to another pair of wells (left hand side). At maturity there is still significant oil  20  left within the oil sand layer  10 . 
     In advanced process  450  Cyr teaches to exploiting a combination of SAGD with huff-and-puff. Within the advanced process  450 , as modeled by Cyr, an initial nine months of injection were followed by three months of production followed by six months of injection followed by three months of production at which time the offset well was converted to full time production under steam trap control. The offset well distance was established at 60 m. Huff-and-puff was started after 3 years of initial SAGD only with a puff duration of nineteen months. For the remainder of the run, SAGD was practiced with the offset well acting as a second SAGD production well. Accordingly to Cyr advanced process  450  resulted in an increased production rate and an increased overall production as evident in  FIG. 4B . However, it is evident that there is still unrecovered oil  20  in the region between the groups of wells even under the advanced aggressive conditions considered by Cyr as evident from advanced process  450  in  FIG. 4A . 
     In order to evaluate the prior art of Cyr simulations were run of a typical oil-sand scenario as described below in Table 2. The relative permeability of oil-water is depicted in  FIG. 4C  but first graph  410  whilst second graph  420  depicts the relative permeability of liquid gas. Also depicted in  FIG. 4C  is third graph  430  depicting the reducing viscosity of bitumen with temperature assumed within the simulations. Data for the simulations was derived from published measurement data filed by Cenovus Energy Inc. in compliance with Canadian Energy Resources Conservation Board requirements for its Christina Lake SAGD activities within the Athabasca oil sands (SAGD 8591 Subsurface, Jun. 15, 2011, (http://www.ercb.ca/portal/server.pt/gateway/PTARGS_0_0_312_249_0_43/http %3B/ercbco ntent/publishedcontent/publish/ercb_home/industry_zone/industry_activity_and_data/in_situ_progress_reports/2011/). The Athabasca oil sands together with the Cold Lake and Peace River oil sands are all in Northern Alberta, Canada and represent the three major oil sands deposits in Alberta that lie under 141,000 square kilometers of boreal forest and peat moss which are estimated to contain 1.7 trillion barrels (270×10 9  m 3 ) of bitumen which are therefore comparable in magnitude to the worlds proven reserves of conventional petroleum. 
     
       
         
               
             
               
               
               
               
             
           
               
                 TABLE 2 
               
             
             
               
                   
               
               
                 Reservoir Characteristics and Key Simulation Parameters: 
               
             
          
           
               
                 Parameter 
                 Value 
                 Parameter 
                 Value 
               
               
                   
               
               
                 Reservoir Pressure 
                 2000 kPa 
                 Initial Oil Saturation 
                 0.85 
               
               
                 Reservoir Temperature 
                     10° C. 
                 Initial Water Saturation 
                 0.15 
               
               
                 Porosity 
                 0.34 
                 Initial Gas Saturation 
                 0 
               
               
                 Permeability 
                   1 D 
                 Reservoir Width 
                 200 m 
               
               
                 Kv/Kh 
                 0.5 
                 Reservoir Thickness 
                  30 m 
               
               
                   
                   
                 Simulation Time 
                  10 years 
               
               
                   
               
             
          
         
       
     
     Additional operating parameters and constraints plus thermal properties of the modeled structure are presented below in Tables 3 to 5 respectively. 
     
       
         
               
             
               
               
               
               
               
             
           
               
                 TABLE 3 
               
             
             
               
                   
               
               
                 Operating Parameters used in Simulations 
               
             
          
           
               
                   
                 Parameter 
                 Value 
                 Parameter 
                 Value 
               
               
                   
                   
               
               
                   
                 Injection Pressure 
                 1800 kPa 
                 Well Length 
                 700 m 
               
               
                   
                 Steam Quality 
                 0.9 
                 Preheating Days 
                 90 
               
               
                   
                 Steam Temperature 
                     200° C. 
               
               
                   
                   
               
             
          
         
       
     
     
       
         
               
             
               
               
             
               
               
               
               
             
           
               
                 TABLE 4 
               
             
             
               
                   
               
               
                 Injection and Production Well Constraints 
               
             
          
           
               
                 Injection Well Constraints 
                 Production Well Constraints 
               
               
                   
               
             
          
           
               
                 Operate Min BHP 
                 800 kPa 
                 Operate Min BHP 
                 800 kPa 
               
               
                 Operate Max Total 
                 350 m 3 / 
                 Operate Max Steam 
                  0.5 m 3 /day 
               
               
                 Surface Wafer 
                 day 
                 Operate Max Total 
                 700 m 3 /day 
               
               
                 Injection Rate 
                 (CWE) 
                 Surface Liquid Rate 
               
               
                   
               
             
          
         
       
     
     
       
         
               
             
               
               
             
               
               
               
               
             
           
               
                 TABLE 5 
               
             
             
               
                   
               
               
                 Thermal Properties 
               
             
          
           
               
                 Thermal Properties 
                 Over-burden/Under-burden 
               
               
                   
               
             
          
           
               
                 Rock Volumetric 
                 2.347E+06 
                 Volumetric 
                 2.35E+06 
               
               
                 Heat Capacity 
                 J/(m 3  · ° C.) 
                 Heat Capacity 
                 J/(m 3  · ° C.) 
               
               
                 Rock Thermal 
                 2.74E+05 
                 Thermal 
                 1.50E+05 
               
               
                 Conductivity 
                 J/(m · day · ° C.) 
                 Conductivity 
                 J/(m · day · ° C. 
               
               
                 Oil Phase 
                 1.15E+04 
               
               
                 Thermal 
                 J/(m · day · ° C.) 
               
               
                 Conductivity 
               
               
                 Water Phase 
                 5.35E+06 
               
               
                 Thermal 
                 J/(m · day · ° C.) 
               
               
                 Conductivity 
               
               
                 Gas Phase 
                 2.50E+03 
               
               
                 Thermal 
                 J/(m · day · ° C.) 
               
               
                 Conductivity 
               
               
                   
               
             
          
         
       
     
     Referring to  FIGS. 4D and 4E  simulation results for a conventional SAGD process according to the prior art of Cyr and others is presented with injector wells disposed vertically above production wells are presented. SAGD well-pair separation of 100 m and vertical injector-producer pair spacing of 4 m are employed with the injector parameters defined above in Table 3 together with the production/injector well constraints and thermal properties presented in Tables 4 and 5. First and second graphs  440  and  450  present contours of pressure and temperature within the simulated oil sand layer after 10 years of SAGD operation. As evident from the temperature profiles in second graph  450  each SAGD well-pair has generated a hot vertical profile that is still cold between them being only approximately 10-20° C. warmer than the original oil sand layer at 10° C. Accordingly as evident from third graph  460  in  FIG. 4D  the oil saturation has only reduced in these vertical hot zones with an effective zone width of approximately 30 m towards the upper region of the vertical hot zones and tapers towards the lower half of the layer cross-section towards the SAGD well-pair. 
     Referring to  FIG. 4E  first to fourth graphs  470  through  485  respectively depict as a function of time over the 10 year modeling cycle:
         the injector pressure (kPa) and steam injection rate (m 3 /day);   the producer pressure (kPa) and oil production rate (m 3 /day);   steam-to-oil ratio (SOR) which is steam injection rate divided by oil production rate;   gas-to-oil (GOR) which is the ratio between gas produced through the SAGD well-pairs and the oil produced.       

     Now referring to  FIG. 5A  there is depicted an oil recovery scenario according to the prior art of Coskuner in US Patent Application 2009/0,288,827 entitled “In-Situ Thermal Process for Recovering Oil from Oil Sands” wherein groups of wells are disposed across the oil sands. Each group of wells each consisting of a vertically-spaced SAGD well pair, comprising an injector well  510  and a producer well  520 , and a single cyclic steam stimulation (CSS) well  530  that is offset from and adjacent to the SAGD well pair comprising injector well  510  and producer well  520 . Although  FIG. 5  shows two such groups of wells, the combined CSS and SAGD process of Coskuner, referred to as CSS-SAGD, can employ a different number of groups, and can have any number of well groups following this pattern. As taught by Coskuner the single wells  530  are located at the same depth as the producer wells  520  although the single wells  530  are taught as being locatable at depths d PROD −0.5×Δd≦d CSS ≦d INJ +0.5×Δd where d PROD , and d INJ  are the depths of the producer well  520  and injector well  510  respectively and Δd=MAG[d INJ −d PROD ]. 
     Accordingly the CSS-SAGD process of Coskuner employs an array of SAGD well pairs comprising injector wells  510  and producer wells  520  with intermediate CSS wells comprising single wells  530 . Coskuner notes that the well configurations of the injector, producer, and injector wells  510 ,  520 , and  530  respectively will depend on the geological properties of the particular reservoir and the operating parameters of the SAGD and CSS processes, as would be known to one skilled in the art. Accordingly the spacing between each SAGD well pair (comprising injector wells  510  and producer wells  520 ) and offset single well  530  will also depend on the properties of the reservoir and the operating parameters of CSS-SAGD process; in particular, the spacing should be selected such that steam chambers from the injector well of the well pair and the single well can come into contact with each other within a reasonable amount of time so that the accelerated production aspect of the process is taken advantage of. 
     As taught by Coskuner the CSS-SAGD process comprises four stages:
         Initial CSS stage, wherein the injector wells  510  (or producer wells  520 ) and the single wells  530  are operated as CSS wells for one or more cycles;   Soak stage, wherein all wells are closed off and the reservoir “soaks;”   SAGD production stage, wherein a SAGD operation is applied to the SAGD well pairs comprising injector wells  510  and producer wells  520  and the single wells  530  are operated as production wells, i.e. where steam is injected into injector wells  510  and the bitumen, and other mobilized elements of the reservoir, is produced from either one or both of the producer wells and single wells  520  and  530  respectively under gravity assisted displacement; and   Blowdown stage, wherein steam injection is terminated and the reservoir is produced to economic limit.       

     As shown in  FIG. 5A  a flow chart illustrates the different steps of the CSS-SAGD process according to Coskuner. Steps  545  to  555  comprise the initial CSS stage wherein in step  545 , steam is injected into the injector and single wells  510  and  530  respectively under the same pressure and for a selected period of time (injection phase). In step  550 , the injector and single wells  510  and  530  respectively are shut in to soak (soak phase). In step  555 , the injector and single wells  510  and  530  respectively are converted into production wells and oil is extracted (producing phase). If additional CSS cycles are desired then steps  545  to  555  are repeated as determined in step  560 . Subsequently the offset single wells  530  are converted to dedicated production wells in step  565  and steam is injected into the injector wells  510  in step  570 . Subsequently when a decision is made regarding the economics of the steam injection in the injector wells  510  these are shut off and the injector wells shut in as identified in step  575  wherein gravity driven production occurs for a period of time as the reservoir cools until production is terminated in step  580 . 
     Accordingly, the well pairs  510 ,  520  and single well initially create early steam chamber structure  590  but evolve with time to expand to later steam chamber  585  wherein the region between the SAGD triangular steam chambers and the essentially finger like steam chamber from the single well  530  merge at the top of the oil sand structure adjacent the overburden. Apart from the region near single well  530  the overall structure of the oil sand reservoir addressed is similar to that of Cyr. 
     Now referring to  FIG. 5B  there are depicted first to fourth images  560 A through  560 D according to the prior art of Arthurs et al in U.S. Pat. No. 7,556,099 entitled “Recovery Process” which represent an end-of-life SAGD production system according to the prior art, with the insertion of a horizontal in-fill well into the end-of-life SAGD production system and subsequent end-of-life position for the SAGD plus in-fill well combination. Accordingly in first image  560 A the typical progression of adjacent horizontal well pairs  100  as an initial SAGD controlled process is depicted wherein a first mobilized zone  110  extends between a first injection well  120  and a first production well  130  completed in a first production well completion interval  135  and into the subterranean reservoir  20 , the first injection well  120  and the first production well  130  forming a first SAGD well pair  140 . A second mobilized zone  150  extends between a second injection well  160  and a second production well  170  completed in a second production well completion interval  175  and into the subterranean reservoir  20 , the second injection well  160  and the second production well  170  forming a second SAGD well pair  180 . As illustrated in first image  560 A these first and second mobilized zones  110  and  150  respectively are initially independent and isolated from each other. 
     Over time, as illustrated in second image  560 B, lateral and upward progression of the first and second mobilized zones  110  and  150  respectively results in their merger, giving rise to common mobilized zone  190 . Accordingly, at some point the economic life of the SAGD recovery process comes to an end, due to an excessive amount of steam or water produced or for other reasons. However, as evident in second image  560 B a significant quantity of hydrocarbons in the form of the bitumen heavy oil, etc remains unrecovered in a bypassed region  200 . Accordingly Arthur teaches to providing a horizontal infill well  210  within the bypassed region  200  where the location and shape of the bypassed region  200  may be determined by computer modeling, seismic testing, or other means known to one skilled in the art. Arthur teaches that the horizontal infill well  210  will be at a level or depth which is comparable to that of the adjacent horizontal production wells, first production well  130  and second production well  170 , having regard to constraints and considerations related to lithology and geological structure in that vicinity, as is known to one ordinarily skilled in the art. 
     Timing of the inception of operations at the infill well  210  as taught by Arthurs is dictated by economic considerations or operational preferences. However, Arthur teaches that an essential element of the invention is that the linking or fluid communication between the infill well  210  and the common mobilized zone  190  must occur after the merger of the first and second mobilized zones  110  and  150  respectively which form the common mobilized zone  190 . Arthur teaches that the infill well  210  is used a combination of production and injection wherein as evident in third image  560 C fluid  230  is injected into the bypassed region  200  and then operated in production mode, not shown for clarity, such that over time the injection well is used to produce hydrocarbons from the completion interval  220 . Accordingly Arthurs teaches to employing a cyclic steam stimulation (CSS) process to the infill well  210  after it is introduced into the reservoir and after formation of the common mobilized zone  190 . 
     Accordingly Arthurs teaches to operating the infill well  210  by gravity drainage along with continued operation of the adjacent first and second SAGD well pairs  140  and  180  respectively that are also operating under gravity drainage. Accordingly, the infill well  210 , although offset laterally from the overlying first injection well  120  and the second injection well  160 , is nevertheless able to function as a producer that operates by means of a gravity-controlled flow mechanism much like the adjacent well pairs. This arises through inception of operations at the infill well  210  being designed to foster fluid communication between the infill well  210  and the adjacent well pairs  100  so that the aggregate of both the infill well  210  and the adjacent well pairs  100  is a unit under a gravity-controlled recovery process. Arthurs repeatedly teaches that early activation of the infill well relative to the depletion stage forming the common mobilized zone  190  is to be avoided as it will prevent or inhibit hydraulic communications between the common mobilized zone  190  and the completion interval  220  formed from the CSS operation of the infill well  210  thereby reducing the recovery efficiency of the concurrent CSS—SAGD process taught. 
     In contrast the inventor has established a regime of operating a reservoir combining SAGD well pairs with intermediate wells wherein recovery efficiency is increased relative to conventional SAGD, the CSS-SAGD taught by Coskuner, and concurrent CSS-SAGD taught by Arthurs, and results in significant recovery of hydrocarbons. According to embodiments of the invention, unlike the prior art, the completion interval extends completely between SAGD pairs. 
     Referring to  FIG. 6  a plurality of wells according to an embodiment of the invention wherein a plurality of wells are shown. Upper wells  602 A,  602 B,  602 C are depicted as substantially parallel and coplanar with each other. Lower wells  604 A,  604 B are also depicted substantially parallel and coplanar with each other. The lower wells  4  are also substantially parallel to the upper wells  2 . However, it is understood variations may arise through the local geology and topography of the reservoir within which the plurality of wells are drilled. Lower well  604 A is defined to be adjacent and associated with upper wells  602 A,  602 B as a functional set, and lower well  604 B is similarly adjacent and associated with upper wells  602 B,  602 C as a second set of wells within the overall array depicted in  FIG. 1 . Thus, upper well  602 B is common to both sets. Additional upper and lower wells can be similarly disposed in the array. Accordingly according to embodiments of the invention such as will be described below in respect of  FIGS. 7 through 24  upper wells  602 A and  602 C are referred to as injector wells, primary injectors, and alike whereas upper well  602 B is referred to as intermediate well, secondary injector, and alike and is operated under different conditions to upper wells  602 A and  602 C such that a pressure differential exists between upper well  602 B and each of the upper wells  602 A and  602 C. 
     The wells  602 ,  604  are formed in a conventional manner using known techniques for drilling horizontal wells into a formation. The size and other characteristics of the well and the completion thereof are dependent upon the particular structure being drilled as known in the art. In some embodiments slotted or perforated liners are used in the wells, or injector structures such as presented supra in respect of  FIGS. 3A and 3B . The upper horizontal wells  602  may be established near an upper boundary of the formation in which they are disposed, and the lower horizontal wells  604  are disposed towards a lower boundary of the formation. 
     Each lower horizontal well  604  is spaced a distance from each of its respectively associated upper horizontal wells  602  (e.g., lower well  604 A relative to each of upper wells  602 A,  602 B) for allowing fluid communication, and thus fluid drive to occur, between the two respective upper and lower wells. Preferably this spacing is the maximum such distance, thereby minimizing the number of horizontal wells needed to deplete the formation where they are located and thereby minimizing the horizontal well formation and operation costs. The spacing among the wells within a set is established to enhance the sweep efficiency and the width of a chamber formed by fluid injected through the implementation of the method according to embodiments of the present invention. 
     The present invention is not limited to any specific dimensions because absolute spacing distances depend upon the nature of the formation in which the wells are formed as well as other factors such as the specific gravity of the oil within the formation. Accordingly, in initiating the wells to production a fluid is flowed into the one or more upper wells  602  in a conventional manner, such as by injecting in a manner known in the art. The fluid is one which improves the ability of hydrocarbons to flow in the formation so that they more readily flow both in response to gravity and a driving force provided by the injected fluid. Such improved mobility can be by way of heating, wherein the injected fluid has a temperature greater than the temperature of hydrocarbons in the formation so that the fluid heats hydrocarbons in the formation. 
     A particularly suitable heated fluid is steam having any suitable quality and additives as needed. Other fluids can, however, be used. Noncondensable gas, condensible (miscible) gas or a combination of such gases can be used. In limited cases, liquid fluids can also be used if they are less dense than the oil, but gaseous fluids (particularly steam) are typically preferred. Examples of other specific substances which can be used include carbon dioxide, nitrogen, propane and methane as known in the art. Whatever fluid is used, it is typically injected into the formation below the formation fracture pressure, as with SAGD. 
     At the same time the lower well(s)  604  associated with the upper well(s)  602  into which the liquid is being injected, to increase the temperature in the region around the upper well(s)  602  so that the viscosity of the oil is reduced, are placed under pressure so that a pressure differential is provided between the wells thereby providing in this embodiment of the invention an increase in mobility of the oil. Accordingly within the embodiment of the invention depicted in  FIG. 6  the pressure differential increase results in an increase oil velocity as shown in Table 1 thereby reducing the time between initial fluid injection and initial production. 
     Referring to  FIG. 7A  there are depicted first and second oil well structures  700 A and  700 B respectively according to embodiments of the invention. As depicted in first oil well structure  700 A an oil bearing structure  740  is disposed between an overburden  750  and rock formation  760 . Drilled into the oil bearing structure  740  towards the lower boundary with the rock formation  760  are pairs of injection wells  710  and production wells  720 . Drilled between these pairs are pressure wells  730 . In operation fluid is injected into the injection wells  710 , such as described supra wherein the fluid, for example, is intended to increase the temperature of the oil bearing structure  740  so that the viscosity of oil is reduced. 
     As operation continues the fluid injected from the injection wells  710  forms an evolving mobilization region above the pairs of wells and recovery of the oil subsequently begins from production wells  720 , this being referred to as the mobilized fluid chamber  770 . According to embodiments of the invention as the mobilized fluid chamber  770  increases in size then pressure wells  730  are activated thereby providing a pressure gradient through the oil bearing structure towards the mobilized fluid chamber  730  thereby providing impetus for the movement of injected fluid and heated oil towards the pressure well  730  as well as to the production well  720 . Accordingly with time the mobilized fluid chamber  770  expands to the top of the oil bearing structure  740  and may expand between the injection wells  710  and pressure wells  730  to recover oil from the oil bearing structure  740  in regions that are left without recovery in conventional SAGD processes as well as those such as CSS-SAGD as taught supra by Coskuner. 
     Optionally the pressure wells  730  may be activated at the initiation of fluid injection into the injection wells  710  and subsequently terminated or maintained during the period of time that the injection wells  710  are terminated and production is initiated through the production wells  720  as time has been allowed for the oil to move under gravitational and pressure induced flow down towards them through the oil bearing structure. Optionally the pressure wells  730  may be operated under low pressure during one or more of the periods of fluid injection, termination, and production within the injection wells  710  and production wells  720 . It would be apparent that with periods of fluid injection, waiting, and production that many combinations of fluid injection, low pressure, production may be provided and that the durations of these within the different wells may not be the same as that of the periods of fluid injection, waiting, and production. 
     Referring to first oil well structure  700 A the pressure wells  730  are shown at the same level as the production wells  720 . In contrast in second oil well structure  700 B the pressure wells  730  are shown at the same level as the injection wells  710 . In  FIG. 7B  the production wells  710  are shown offset towards the pressure well  730 . In a variant of  FIG. 7B  where the oil bearing structure  740  has a width that supports multiple sets of injector—pressure—pressure wells then each injection well  710  may be associated with a pair of production wells  720  wherein the production wells are offset laterally each to a different injector well. 
     Referring to  FIG. 8  there is depicted an oil well structure  800  according to an embodiment of the invention. As depicted an oil bearing structure  840  is disposed between an overburden  850  and rock formation  860 . Drilled into the oil bearing structure  840  towards the lower boundary with the rock formation  860  are pairs of primary injection wells  810  and production wells  820 . Drilled between these pairs are pressure wells  830  and secondary injection wells  880 . During an initial phase fluid is injected into the primary injection wells  810 , such as described supra wherein the fluid is intended, for example, to increase the temperature of the oil bearing structure  840  so that the viscosity of oil is reduced. 
     As operations continue the fluid injected from the primary injection wells  810  forms an evolving region above the pairs of wells and recovery of the oil subsequently begins from production wells  820  wherein the mobility of the oil has been increased within this evolving region through the fluid injected into primary injection wells  810 . As the mobilized fluid chamber  870  increases in size then pressure wells  830  are activated providing a pressure gradient through the oil bearing structure towards the mobilized fluid chamber  870  thereby providing impetus for the movement of injected fluid and heated oil towards the pressure well  830  as well as to the production wells  820 . Accordingly with time the mobilized fluid chamber  870  expands to the top of the oil bearing structure  840  and may expand between the injection wells  810  and pressure wells  830  to recover oil from the oil bearing structure  840  in regions that are usually left in conventional SAGD processes as well as others such as CSS-SAGD as taught supra by Coskuner. 
     However, unlike first oil well structure  700  the oil well structure  800  includes secondary injection wells  880  that can be used to inject fluid into the oil bearing structure  840  in conjunction with primary injections wells  810  and pressure wells  830 . Accordingly during an exemplary first recovery stage the primary injection wells  810  are employed and the pressure wells  830  may be activated to help draw oil towards and through the region of the oil bearing structure  840  that is left without recovery from conventional SAGD. Subsequently during recovery from the production well  820  with injection halted through the primary injection wells  810  the pressure wells  830  may be engaged to draw oil towards the pressure wells  830 . Subsequently when injection re-starts into the primary injection wells  810  a fluid may also be injected into the secondary injection wells  880 . This fluid may be the same as that injected into the primary injection wells  810  but it may also be different. 
     It would be apparent that the timing of the multiple stages of the method according to embodiments of the invention may be varied according to factors such as oil bearing structure properties, spacing between production and injection wells, placement of pressure wells etc. For example, conventional SAGD operates with an initial period of fluid injection followed by production phase, then cyclic injection/production stages. According to some embodiments of the invention the pressure wells may be held at pressure during the injection phase, during the production phase, during portions of both injection and production phases or during periods when both injection and production wells are inactive. This may also be varied according to the use of the primary and secondary injection wells. It would be further evident that ultimately the pressure wells become production wells as oil pools around them. According to another embodiment of the invention fluid may be injected continuously through the primary injection wells  810  and secondary injection wells  880  or alternatively through the primary injection wells  810  and pressure wells  830 . Similarly primary injection wells  810  may be injected continuously whilst pressure wells  830  are operated continuously under low pressure. 
     Referring to  FIG. 9  there is depicted second oil well structure  900  according to an embodiment of the invention. As depicted an oil bearing structure  940  is disposed between an overburden  950  and rock formation  960 . Drilled into the oil bearing structure  940  towards the lower boundary with the rock formation  960  are pairs of primary injection wells  910  and production wells  920 . However, unlike the oil bearing structures considered above in respect of  FIGS. 7 and 8  the overburden  950  and rock formation  960  result in an oil bearing structure  940  of varying thickness such that deploying injection/production pairs is either not feasible or economical in regions where the separation from overburden  950  to rock formation  960  are relatively close together. Accordingly in the regions of reduced thickness additional wells, being pressure wells  930 A and  930 B are drilled. In this configuration pressure wells  930 A and  930 B induce the depletion chamber, also referred to supra as the mobilized fluid chamber, formed by the injection of the fluid through the injection well  910  to extend towards the reduced thickness regions of oil bearing structure  940 . Subsequently the pressure wells  930 A and  930 B may also be employed as production wells as the reduced velocity oil reaches them. In some scenarios pressure wells  930 A and  930 B may be operated under low pressure and in others under pressure to inject a fluid at elevated temperature. 
     This may be extended in other embodiments such as presented in  FIG. 10  according to an embodiment of the invention to provide recovery within a thin oil bearing structure  1040  as depicted within oil structure  1000 . As such there are depicted injection wells  1010  with pressure wells  1030  disposed between pairs of injection wells  1010 . As fluid injection occurs within the injection wells  1010  the pressure wells  1030  provide a “pull” expanding the chambers towards them whilst they also propagate vertically within the oil bearing structure  1040 . Accordingly as there are no vertically aligned production wells with the injections wells  1010  as in conventional or modified SAGD processes within the oil structure  1000  then the injection may be terminated and extraction undertaken from the injection wells  1010  and pressure wells  1030 . As depicted the pressure wells  1030  are at a level similar to that of the injection wells  1010  but it would be evident that alternatively the pressure wells  1030  may be at a different level to the injection wells  1010 , for example closer to the overburden  1050  than to the bedrock  1060 , and operating under injection rather than a lower pressure scenario. 
     Whilst within the embodiments presented in respect of  FIGS. 6 to 10  the configurations have been with essentially horizontal oil well configurations in addressing oil bearing structures such as oil sands (tar sands) the approaches identified within these embodiments of the invention may be applied to vertical well configurations as well as others. 
     Referring to  FIG. 11  there is shown a combined oil recovery structure  1100  employing both vertical and horizontal oil well geometries. Accordingly there is shown a geological structure comprising overburden  1150 , oil bearing layer  1140 , and sub-rock  1160 . Shown are vertical injection wells  1110  coupled to steam injectors  1170  that are drilled into the geological structure to penetrate into the upper portion of the oil bearing layer  1140 . Drilled into the lower portion of the oil bearing layer  1140  are production wells  1120  and pressure wells  1130 . In operation the vertical injection wells  1110  inject a fluid into the upper portion of the oil bearing structure  1140  with the intention of lowering the viscosity of the oil within the oil bearing layer  1140 . In an initial stage of operation operating the vertical injection wells  1110  and production wells  1120  results in a SAGD-type structure resulting in oil being recovered through the production wells. However, in common with other SAGD structures the resulting oil-depleted chamber formed within the oil bearing layer  1140  results in regions that are not recovered besides these oil-depleted chambers. Accordingly the pressure wells  1130  are activated to create a pressure gradient within the oil bearing layer  1140  such that the oil-depleted chamber expands into these untapped regions resulting in increased recovery from the oil bearing layer  1140 . Optionally, the pressure wells  1130  may inject a fluid into the oil bearing layer  1140 . Within another embodiment of the invention the vertical injection wells  1110  may be disposed between the production wells  1120  either with or without the pressure wells  1130 . 
     According to an alternate embodiment of the invention between the initial SAGD-type recovery through the production wells  1120  and subsequent engagement of the pressure wells  1130  the steam injection process may be adjusted. During the initial SAGD-type recovery steam injection may be performed under typical conditions such that the injected fluid pressure is below the fracture point of the oil bearing layer  1140 . However, as the initial SAGD-type recovery is terminated with the production wells  1120  the fluid injection process may be modified such that fluid injection is now made at pressures above the fracture point of the oil bearing layer  1140  so that the resulting fluid flow from subsequent injection is now not automatically within the same oil-depleted chamber. In some embodiments of the invention the fluid injector head at the bottom of the injection well  1110  may be replaced or modified such that rather than injection being made over an extended length of the injection well  1110  the fluid injection is limited to lateral injection. 
     Optionally the injection well  1110  may be specifically modified between these stages so that the fluid injection process occurs higher within the geological structure and into the overburden  1150 . Alternatively the injection wells  1110  may be terminated within the overburden  1150  and operated from the initial activation at a pressure above the fracture pressure. Such a structure being shown in  FIG. 12  with recovery structure  1200 . 
     As shown in  FIG. 12  injection wells  1210  terminate within the overburden  1250  of an oil reservoir comprising the overburden  1250 , oil bearing layer  1240 , and under-rock  1260 . Drilled within the oil bearing layer  1240  are production wells  1220  and pressure wells  1230 . Injection of fluid at pressures above the fracture limit of the overburden  1250  results in the overburden fracturing and forming a fracture zone  1270  through which the fluid penetrates to the surface of the oil bearing layer  1240 . The injected fluid thereby reduces the viscosity of the oil within the oil bearing layer  1240  and a SAGD-type gravity feed results in oil flowing towards the lower portion of oil bearing layer  1240  wherein the production wells  1220  allow the oil to be recovered. Also disposed within the oil bearing layer  1240  are pressure wells  1230  that are disposed higher within the oil bearing layer  1240  than the production wells. The purpose of the pressure wells  1230  being to provide a driving mechanism for widening the dispersal of the injected fluid within the oil bearing layer  1240  such that the spacing of the injection wells  1210  and potentially the production wells  1220  may be increased. 
     Whilst the pressure wells  1230  and production wells  1230  have been presented as horizontal recovery structures within the oil bearing layer  1240  it would be evident that alternatively vertical wells may be employed for one or both of the pressure wells  1230  and production wells  1230 . Likewise, optionally the injection wells  1210  may be formed horizontally within the overburden. It would also be apparent that after completion of a first production phase wherein the fluid injected into the injection well  1210  is one easily separated from the oil at the surface or generated for injection that a second fluid may in injected that provides additional recovery, albeit potentially with increased complexity of separation and injection. 
     Referring to  FIG. 13  there is depicted a vertical recovery structure  1300  according to an embodiment of the invention. As shown a production well  1310  is drilled into the oil bearing layer  1340  of a geological structure comprising the oil bearing layer  1340  disposed between overburden  1350  and lower-rock  1360 . Production well  1310  has either exhausted the natural pressure in the oil bearing layer  1340  or never had sufficient pressure for free-flowing recovery of the oil without assistance. Accordingly, production from the production well  1310  is achieved through a lifting mechanism  1320 , as known in the prior art. Subsequently, production under lift reduces. Accordingly, the well head of the production well is changed such that a fluid injector  1370  is now coupled to the same or different pipe. Accordingly fluid injection occurs within the production well  1310  for a predetermined period of time at which point the fluid injection is terminated, the oil pools and recovery from the lifting process can be restarted by replacing the fluid injector  1370  with the lifting mechanism  1370 . 
     Optionally, the fluid injector and lifting mechanism  1370  may be coupled though a single well head structure to remove requirements for physically swapping these over. During fluid injection additional expansion of the fluid&#39;s penetration into the oil bearing layer  1340  may be achieved through the operation of pressure wells  1330  which are disposed in relationship to the production well  1310 . During the fluid injection into the production well  1310  the fluid injector may be disposed at a depth closer to the upper surface of the oil bearing structure  1340  rather than the closer to the lower limit during oil recovery. Likewise the lower limit of the pressure well  1330  is closer to the upper surface of the oil bearing structure  1340  as the intention is to encourage fluid penetration into the upper portion of the oil bearing structure  1340  between the oil depleted zones  1380  formed from the injection into the production wells  1310 . 
     According to another embodiment of the invention a single well drilled into an oil bearing structure may be operated through a combination of low pressure, high pressure, fluid injection, and oil extraction or a subset thereof. Referring to  FIG. 14  there is shown an oil recovery structure  1400  according to an embodiment of the invention wherein a single well  1410  has been drilled into an oil bearing structure  1430  disposed between an overburden  1420  and bedrock  1440 . As such the single well  1410  is for example operated initially under fluid injection, followed by a period of time at low pressure and then extraction of oil. Such a cycle of injection—low pressure—extraction being repeatable with varying durations of each stage according to factors including but not limited to characteristics of oil bearing structure, number of cycles of injection—low pressure—extraction performed, and characteristics of the oil mixture being recovered. 
     Optionally the fluid injected in the cycles may be changed or varied from steam for example to a solvent or gas. It would also be evident that the cyclic sequence may be extended to include during some cycles, for example towards the later stages of recovery, a stage of high pressure injection such that an exemplary sequence may be high pressure—injection—low pressure—extraction. Further the pressures used in each of high pressure, injection and low pressure may be varied cycle to cycle according to information retrieved from the wells during operation or from simulations of the oil bearing structure. 
     Referring to  FIG. 15  there is depicted an exemplary drill string according to an embodiment of the invention for use in a multi-function well such as that described supra in respect of  FIG. 14 . Accordingly rather than requiring replacement of the drill string during each stage of the 3 step (injection—low pressure—extraction) or 4 step (high pressure—injection—low pressure—extraction) process a single drill string is inserted and operated. As discussed supra in respect of SAGD and other prior art approaches the timescales for each stage are typically tens or hundreds of days for each step. Whilst it is possible to consider replacing the drill string in each stage this requires additional effort and cost to be expended including for example deploying personnel to the drill head and maintaining a drilling rig at the drill head or transporting one to it. As such it would be beneficial to provide a single drill string with multiple functionality connected to the required infrastructure at the drill head. Accordingly such a multi-function drill string could be controlled remotely from a centralized control facility allowing multiple drill strings to be controlled without deploying manpower and equipment. 
     Accordingly in  FIG. 15  there is depicted drill string assembly  1500  comprising well  1510  within which the drill string is inserted comprising injector portion  1530 , pressure portion  1520  and production portion  1540 . For example the exterior surfaces of each of these portions being for example such as described supra in respect of  FIGS. 3A and 3B  with respect to US Patent Applications 2008/0,251,255 and 206/0,048,942. Accordingly in use the drill string assembly  1500  can provide for fluid injection through injector portion  1530 , extraction through production portion  1540  and low pressure through pressure portion  1520 . 
     Optionally pressure portion  1520  may be coupled to a pressure generating system as well as a low pressure generating system allowing the pressure portion  1520  to be used for both high pressure and low pressure steps of a 4 step sequence. It would be evident to one skilled in the art that the exterior surfaces may be varied according to other designs within the prior art and other designs to be established. Alternatively the drill string assembly  1500  may be a structure such as depicted in sequential string  1550  wherein the injector portion  1530 , pressure portion  1520  and production portion  1540  are sequentially distributed along the length of the sequential string  1550 . 
     Now referring to  FIG. 16A  there are depicted first to third images  1610  through  1630  respectively depicting the pressure, temperature and oil depletion for a SAGD process according to an embodiment of the invention with a 75 m well-pair separation, 0 m offset between injector and producer wells within each well-pair, and intermediate pressure wells. Extracted data from the simulations was used to generate the first to fourth graphs  1640  through  1670  that depict injector and producer pressure and steam injection rates together with SOR and field production comparison. Within this embodiment injection into the intermediate pressure well was initiated from the beginning of the simulation with an injection pressure of 2000 KPa and steam quality of 0.99. As evident from first graph  1640  in  FIG. 16B  no steam injectivity was evident until approximately 2350 days. After 2500 days, considerable rates steam rates were achieved, which also resulted in significant increase in bitumen production as evident in third graph  1660  in  FIG. 16B . The entire zone between the well pairs was swept, which could be seen from the oil saturation profile in third image  1630  of  FIG. 16A  and the increased production against a baseline SAGD process evident in fourth graph  1670 . The rise in SOR in second graph  1750  after 3500 days indicates that the intermediate injector could be turned off, as it is has completed its objective and there is no point of injecting steam from it anymore. 
     Now referring to  FIG. 17A  there are depicted first to third images  1710  through  1730  respectively depicting the pressure, temperature and oil depletion for a SAGD process according to an embodiment of the invention with a 75 m well-pair separation, 5 m offset between injector and producer wells within each well-pair, and intermediate pressure wells. Extracted data from the simulations was used to generate the first to fourth graphs  1740  through  1770  that depict injector and producer pressure and steam injection rates together with SOR and field production comparison. With the offset in injector and producer wells then as in previous case discussed above in respect of  FIGS. 5C and 5D  the start-up was delayed until approximately 250 days. However, also as a result of the inward shift of producers, earlier steam injectivity from the intermediate injector, i.e. before 2,500 simulation days, was achieved with considerable rates as depicted in first graph  1740  in  FIG. 17B . Similarly, bitumen was produced from the untapped zone at high rates as evident from third graph  1760  in  FIG. 17B  and the increased production against a baseline SAGD process evident in fourth graph  1770 . Further as evident from first and second graphs  1740  and  1750  respectively in  FIG. 17B  a decrease in steam injection rates for the injection wells is evident leading to a rise in SOR. 
     As the intermediate injector is approximately 37 m away from the producers within the SAGD well pairs establishing communication between the producers takes time as evident from the results presented within  FIGS. 16A through 17B  respectively. Now referring to  FIG. 18A  there are depicted first to third images  1810  through  1830  respectively depicting the pressure, temperature and oil depletion for a SAGD process according to an embodiment of the invention with a 75 m well-pair separation, 5 m offset between injector and producer wells within each well-pair, and intermediate pressure wells. However, unlike  FIGS. 17A and 17B  steam injection was delayed into the intermediate pressure well for 5 years to allow for the 37.5 m separation between outer injector well and intermediate pressure well. Extracted data from the simulations was used to generate the first to fourth graphs  1840  through  1870  that depict injector and producer pressure and steam injection rates together with SOR and field production comparison. 
     With the offset in injector and producer wells then as in previous case discussed above in respect of  FIGS. 5C and 5D  the start-up was delayed until approximately 250 days. Also as a result of the delayed initiation in injection to the intermediate pressure well the earlier steam injectivity depicted within first graph  1740  of  FIG. 17B  can be seen to be delayed in first graph  1840  of  FIG. 18B . However, the considerable oil production rates are still evident as shown by third graph  1860  in  FIG. 18B  and the increased production against a baseline SAGD process evident in fourth graph  1870 . The previously untapped zone from the prior art was swept as evident from third image  1830  of  FIG. 18A . Further as evident from first and second graphs  1840  and  1850  respectively in  FIG. 18B  a decrease in steam injection rates for the injection wells is evident leading to a rise in SOR as the previously untapped zone is swept wherein the steam injection in the intermediate injector well may be terminated and optionally the injector well now operated as a producer. Similar options exist in respect of the previous embodiments of the invention described above in respect of  FIGS. 16A through 17B . As evident the timing of the peak oil production is now timed comparably to that in  FIG. 16B , approximately 3200 days as opposed to 3300 days. However, the intermediate injector is operated for a reduced period of time compared to the scenario in  FIGS. 17A and 17B  where extended steam injection of approximately 2000 days versus approximately 650 days in the scenarios of  FIGS. 16A, 16B, 18A and 18B  results in advancing peak oil by approximately 500 days and clearing the oil reservoir quicker. 
     Referring to  FIG. 19A  there are depicted first to third images  1910  through  1930  respectively depicting the pressure, temperature and oil depletion for a SAGD process according to an embodiment of the invention with a 75 m well-pair separation, 0 m offset between injector and producer wells within each well-pair, and intermediate pressure well. However, in this case, the operating parameters of the intermediate injection well were matched with the exterior injection wells, wherein the pressure and steam quality were changed to 1800 kPa and 0.9 respectively. Accordingly it is evident from the first to third images  1910  through  1930  in  FIG. 19A  respectively depicting the pressure, temperature and oil depletion within the reservoir that recovery of the central zone was not possible to any substantial degree even in the 10 year simulation run performed to generate these first to third images  1910  through  1930 . Similarly referring to first to fourth graphs  1940  through  1970  in  FIG. 19B  it can be seen that no significant steam injection occurs and the resulting oil and gas production volumes are essentially unchanged from those of the corresponding baseline analysis. 
     Now referring to  FIG. 20A  there are depicted first to third images  2010  through  2030  respectively depicting the pressure, temperature and oil depletion for a SAGD process according to an embodiment of the invention with a 75 m well-pair separation, 0 m offset between injector and producer wells within each well-pair, and intermediate pressure well. However, in this case, the operating parameters of the exterior injection wells were matched with the intermediate injection well, wherein the pressure and steam quality were changed to 2000 kPa and 0.99 respectively for the injector wells within the SAGD well pairs. Accordingly it is evident the operating pressure of the injector wells and the differential between them plays an important role in establishing the start-up of intermediate injector and the evolution of the temperature—pressure profile within the reservoir and the resulting oil and gas recovery. In  FIG. 20B  first to fourth graphs  2040  through  2070  depict the injector well characteristics, production well characteristics, SOR, and comparison of the process against a baseline process. Accordingly it can be seen that the intermediate injector was opened and operating since start of the simulation, it could be seen that approximately after 3000 days, it had some considerable injection rates. In comparison with the previous case of 1800 KPa, depicted in  FIGS. 19A and 19B , it can be seen that it performed slightly better due to higher steam pressure and quality. 
     Referring to fourth graph  2070  in  FIG. 20B  presenting the field production comparison with the baseline simulations still shows that it was not as productive in 10 years. Accordingly in comparison to the preceding simulations in respect of  FIGS. 16A through 18B  it is evident that the intermediate injector pressure plays an important role in the start-up of the intermediate injector and that once the oil has been heated sufficiently and is ready to be mobilized, it is driven towards the producers by the higher pressure of the intermediate injector. Moreover, higher steam pressure from the intermediate injector overcomes the injection from the injectors of the SAGD pairs and reduces or terminates their injectivity by increasing the pressure in surrounding the reservoir, evident as adjacent well grid blocks within the profiles from the simulation run in  FIG. 20A . 
     Now referring to  FIG. 21A  there are depicted first to third images  2110  through  2130  respectively depicting the pressure, temperature and oil depletion for a SAGD process according to an embodiment of the invention with a 37.5 m well-pair separation wherein there is no offset between injector and producer wells within each well-pair, and all injector wells are now operated at the same pressure. Extracted data from the simulations was used to generate the first to fourth graphs  2140  through  2170  in  FIG. 21B  that depict injector and producer pressure and steam injection rates together with SOR and field production comparison. Not surprisingly almost the entire reservoir has been swept by the end of the 10 year simulation and high oil and gas production are evident with very low SOR at peak production. However, SOR picks up rapidly after 2500 days as the production tails rapidly as evident from the very sharp drop in oil production of the first group of curves which represent producers  1 ,  2  and  4  (the central group). It is expected that similar behaviour would be evident in the other producers if the simulation was over a wider region such that the SOR would climb more rapidly in a large reservoir with small injector-producer well pair spacing. It would be evident to one skilled in the art that the reduced separation coupled with embodiments of the invention wherein SAGD well pairs are interspersed with injector wells operating at higher pressure than the injectors within each SAGD well paid would lead to similar sweeping of the complete reservoir but without the requirement for the additional producer wells to be drilled and populated. 
       FIGS. 25-26  show top views of non-parallel well configurations. The injector wells ( 2510 ) and ( 2610 ) are vertically spaced from the lower producer wells ( 2520 ) and ( 2620 ) and are in a non-parallel relationship with them. The secondary wells ( 2530 ) and ( 2630 ) are laterally offset to both the injector wells and the producer wells. 
     Now referring to  FIG. 22  there are depicted first and second oil bearing structures  2200 A and  2200 B respectively wherein an oil bearing layer  2240  is disposed between upper and lower geological structures  2250  and  2260  respectively. Within the oil bearing layer  2240  injector wells  2220  are disposed together with production wells  2210  with low or zero vertical offset and laterally disposed from these groupings are pressure wells  2230 . Referring to  FIG. 23A  there are depicted first to fourth images  2310  through  233  respectively depicting reservoir pressure, temperature and oil depletion after 10 years wherein all injector wells and producer wells are disposed on the same vertical plane within the reservoir wherein injectors  1  and  2  associated with each SAGD pair are 75 m apart, intermediate injector is symmetrically disposed between these, and the producer wells are offset towards the intermediate well by 5 m as in other simulations presented above but are on the same horizontal plane, i.e. no vertical offset. 
     Referring to  FIG. 23B  first and second graphs  2340  and  2350  depict the injector and producer characteristics for the SAGD well pair/intermediate injector well configuration described above in respect of  FIG. 23A  wherein all wells were disposed 1 m away from the bottom of the same 30 m thick reservoir for simulation purposes. As with other embodiments of the invention described above in respect of  FIGS. 16A through 18B  the intermediate injector well was operated at 2000 KPa and 0.99 steam quality compared to 1800 kPa for the SAGD well pair injectors. As anticipated common vertical placement of the SAGD well pair has an initial adverse effect on the growth of steam chamber. Steam breakthrough occurs after 90 days of pre-heating in this case and as anticipated the steam chamber grows in a column between in the SAGD injector and producer wells. In the meantime, preheating of the intermediate injector was active and after 2500 days, bitumen was heated enough that it could be mobilized towards the producers by the intermediate injector in common with preceding simulations and consequently steam injection in the reservoir from the intermediate injectors is possible. It would be evident that if the simulated reservoir has been thin, for example 5m or 10 m, then the time to steam injection from the intermediate well at the same separation would occur earlier due to the modified pressure—temperature profile within the reservoir. However, in each instance the lateral SAGD well pair allows production to be achieved within a thin reservoir rather than the conventional thick reservoirs considered within the prior art. 
     Now referring to  FIG. 24A  there are depicted first to third images  2410  through  2430  respectively depicting the pressure, temperature and oil depletion for a SAGD process according to an embodiment of the invention with a 75 m well-pair separation wherein there is no offset between injector and producer wells within each well-pair, and in addition to the intermediate injector, injector  4  disposed between injectors  1  and  2  forming the SAGD well pairs with producers  1  and  2  respectively, additional injectors, injectors  3  and  5  are disposed laterally offset to the other side of the SAGD pairs to the intermediate injector well to model a scenario representing a more extensive reservoir. Extracted data from the simulations was used to generate the first to fourth graphs  2440  through  2470  in  FIG. 24B  that depict injector and producer pressure and steam injection rates together with SOR and field production comparison. Non-SAGD well pair injectors, injectors  3  to  5  respectively, were operated at 2000 kPa as opposed to 1800 kPa for the injector wells within each SAGD pair. Not surprisingly almost the entire reservoir has been swept by the end of the 10 year simulation and high oil and gas production rates are evident with very low SOR at peak production around 3000-3500 days. 
     All simulations within the preceding analysis of the prior art and embodiments of the invention were run with a permeability of the oil bearing reservoir of 1 darcy (9.869233×10 −13  m 2 ). Increased permeability of the oil bearing reservoir would reduce the timescales over which embodiments of the invention provide benefit of increased oil and/or gas production as well as allowing increased spacing between SAGD well pairs and intermediate injector wells. 
     Whilst the embodiments of the invention presented above in respect of  FIGS. 6 to 23B  have been primarily described in respect of oil sands (tar sands) the principles are applicable to other oil reservoirs_and reservoirs of chemicals recoverable from permeable formations including but not limited to sands. Within some embodiments of the invention the pressure applied to the pressure wells may vary from vacuum or near-vacuum to pressures that whilst significant in terms of atmospheric pressure are substantially less than those existing within the formation through which the well is bored. Further, as discussed supra in respect of some embodiments with the existence of multiple stages in these oil recovery systems including, but not limited, injection (of fluid), production (of oil) and resting (between injection and production) and the ability to vary the duration of each stage, the order of stages, and the repetitions thereof that multiple sequences of injection into injection wells, extraction from production wells, as well as operation of the pressure wells under low pressure, high pressure, injection and extraction or combinations thereof that a wide range of resulting combinations of operation sequences exist for the embodiments of the invention. The embodiments presented supra being exemplary in nature to present some combinations of these sequences. 
     Within the embodiments of the invention described above these have been described with respect to substantially horizontal and/or vertical injection, production, and pressure wells. It would be evident to one skilled in the art that the approaches described may be exploited with injection, production, and pressure wells that are disposed at angle with respect to the oil bearing formation. 
     However, in other embodiments of the invention the pressure applied to the pressure wells may be significantly higher than the pressure in the formation through which the well is bored such the pressure from the pressure well acts to increase the flow velocity of the oil within the reservoir thereby allowing the initial time from fluid injection to first oil production to be reduced. Equally in other embodiments of the invention the pressure wells may be initially employed with high pressure to reduce time to first oil or even reduce time for oil depletion within the chamber formed from fluid injection and then the pressure reduced to low pressure such that the secondary oil recovery from those regions of the reservoir not currently addressed through the injected fluid are accessed. In other embodiments of the invention such high pressure application may be employed to deliberately induce fracturing within the oil bearing structure. Subsequently the high pressure being replaced with low pressure or near-vacuum alone or in combination with injection of fluids from other wells. 
     It would also be evident that whilst the discussions supra have been for example in respect of oil bearing structures such as oil sands and convention oil reservoirs that the techniques presented may be exploited in other scenarios. Further, they may be exploited for primary production, secondary recovery, tertiary recovery, etc or combinations thereof. Further, it would be evident that in some scenarios the techniques may be applied to a previously worked oil bearing structure where economic factors and/or other factors such as sovereignty issues etc may make the re-opening of such previously worked oil bearing structures to recover oil previously unrecovered through prior primary, secondary, and even tertiary methods known in the prior art. Additionally, the ability to increase overall yield from an oil bearing structure may adjust the economic viability of particular oil bearing structures thereby allowing such reserves that were considered uneconomic to be exploited economically. 
     The above-described embodiments of the present invention are intended to be examples only. Alterations, modifications and variations may be effected to the particular embodiments by those of skill in the art without departing from the scope of the invention, which is defined solely by the claims appended hereto.