bluuebunny/crossref_metadata_2025 huggingface dataset:
A Case Study of Foamy Oil Recovery in the Patos-Marinza Reservoir, Driza Sand, Albania
Authors: Bennion D.B. , Mastmann M. , Moustakis M.L.
Published: March 2010

With a current recovery of only 5%, Albania's largest oilfield, Patos-Marinza, (first commercially produced in 1939) still contains potentially more than 100 MMbbl of reserves of 10 to 12 ° API oil at a depth of 1,600 m. A consortium consisting of Albpetrol Albania, Preussag Energie (Germany), Premier Oil (Britain), and the IFC (the private sector arm of the World Bank) are making plans to improve oil recovery in the area.

Test wells producing 1 to 2 m3/d yielded large rate improvements to over 30 m3/d using "progressive cavity pumps" up to 30 m3/d with producing sand cuts around 10 to 35%. PVT analysis of the oil, with a relatively high solution GOR of 31 m3/m3, shows a strong tendency to foam (gas in microbubbles without forming a continuous gas phase) below the bubble point, near the initial reservoir pressure. Core tests with different depletion rates resulted in primary oil recoveries of greater than 30%.

This paper discusses the detailed suite of laboratory measurements used to examine the Driza crude oil, in the context of present theories of foamy oil and cold heavy oil production with sand (CHOPS).

Introduction

The Patos-Marinza oilfield is an onshore field located east of the city of Fier in South Central Albania (Figure 1). It occupies an area of approximately 24,000 hectares and was discovered in 1926, with commercial oil production starting in the early 1930s. Development to the north continued with drilling of over 2,300 wells, reaching the boundaries of the field in the late 1980s.

The main sandstone reservoirs dip at 8 ° to 13 ° from an outcrop in the South containing mineable tar sands to the original oil water contacts at 1,800 m in the north. There are multiple stacked sand reservoirs of Upper Miocene (Messinian) age, the most important ones being the Gorani, Driza, and Marinza (top to bottom). The Driza reservoir contains the majority of the OOIP and reserves. It consists of up to six sand layers numbered from top to bottom, with D1 being the main sand continuous throughout the field. The Driza is a suite of unconsolidated sandstones with porosity of 25 - 28% and net pay varying areally from 7 to 95 m (south to north).

Oil gravity also varies throughout the field depending on the depth of the reservoir and the type of formation. The Marinza oil (north) has a gravity up to 825 kg/m3 (40 ° API) due to greater depths and a closer position areally to the source rock. The oil gravity in the Patos area (southern half of the field) is about 998 kg/m3 (11 ° API) with dead oil viscosity over 9,000 mPa.s under reservoir conditions.

Due to the unfavourable fluid properties, oil recovery to date in the entire reservoir amounts to less than 5% under depletion drive. The wells with a 2.5 acre spacing generally produce less than 1 M3/d of oil with tubing insert pumps landed halfway to bottom due to equipment limitations.
Lab-Scale Numerical Simulation of SAGD Process in the Presence of Top Thief Zones: A Mechanistic Study
Authors: Law D.H.S. , Nasr T.N. , Good W.K.
Published: March 2010

There is a major concern in the steam-assisted gravity drainage (SAGD) process that the existence of thief zones such as top water and/or a gas cap overlying the oil sand deposit has a detrimental effect on the oil recovery. The objective of this numerical study is to investigate the mechanisms that govern the oil and steam loss during the SAGD process in the presence of a top water zone or a gas cap.

The reservoir model, STARS, developed by the Computer Modelling Group (CMG) Ltd. was first validated based on history matching of two 3D SAGD laboratory experiments with a top water zone and a gas cap, respectively. The experiments that were designed to mimic SAGD processes in the Athabasca region were conducted at field conditions of reservoir pressure and steam injection temperature. It was found that STARS was capable of history matching the top water and gas cap experiments. Therefore, it is believed that the numerical simulation captured the major mechanism of oil movement from the oil zone into the top thief zones as observed in the experiments.

Lab-scale numerical sensitivity study indicated that oil movement from the oil zone into the top thief zones occurred when a very small pressure gradient existed between the oil zone and the top thief zone (e.g., < 10 kPa/m). Higher-pressure gradients resulted in more oil and steam movements into the top thief zone, less oil production, and a higher steam-oil ratio.

Introduction

There is a major concern by Alberta oil producers that the production of natural gas in association with oil sands would lower reservoir pressure, reduce oil recovery, and may prohibit the economic recovery of any oil. The Alberta Department of Energy (ADOE) and Alberta Energy and Utilities Board (AEUB) initiated a series of field-scale numerical modelling studies(1, 2) to assess the potential applicability of the steam-assisted gravity drainage (SAGD) oil recovery process under a variety of reservoir conditions such as reservoir thickness, reservoir depth, initial pressure, oil saturation, and the presence of top water zones and gas caps. It was found that top water zones and gas caps are thief zones to the SAGD process. These thief zones have a detrimental effect on SAGD recovery performance, especially when the pressure in the thief zones is reduced below optimum SAGD operating pressures due to natural gas production. Movement of oil into the top water zones and gas caps is simulated to occur. The volume of this oil seems to be generally proportional to the amount of outflow from the pattern due to the thickness of the top water zones/gas caps and the pressure difference between the steam chamber and the top thief zones. SAGD process costs depend on the amount of steam that flows into the top water zones and gas caps, from which no oil is produced.

A case in point is the Surmont oil sands lease, which Gulf planned to develop with a SAGD pilot starting in June 1997 followed quickly by commercial development.
A Supplemental Discussion of Productivity Formulae of Horizontal Wells
Authors: Lu J. , Lin T. , Rogers R. , Lu T.
Published: March 2010

This paper presents a supplemental discussion of productivity formulae for horizontal wells using a uniform line sink model. Formulae are given for the productivity of horizontal wells in steady state in an infinite lateral extent drainage reservoir with impermeable top and bottom boundaries. This paper also focuses on the effects of different boundary conditions on the productivity of a horizontal well. Significant differences in the productivity of a horizontal well in a reservoir with different drive mechanisms are demonstrated.

Introduction

In Reference (1), Jing Lu presented new productivity formulae for horizontal wells, which are derived from the three-dimensional solution of the Laplace Equation, as opposed to two-dimensional or pseudo-three-dimensional solutions used in the previous Equations in References (2), (3), (4), and (5). Lu's formulae are given for the productivity of horizontal wells in ellipsoidal drainage reservoirs and infinite lateral extent drainage reservoirs with gas cap or bottom water.

In this paper, formulae are given for the productivity of horizontal wells in steady state in an infinite lateral extent drainage reservoir with impermeable top and bottom boundaries. The significant effects of different boundary conditions on the productivity of a horizontal well are also demonstrated.

Horizontal Well Model

Figure 1 is the model of a horizontal well in an infinite lateral extent drainage reservoir.

The following assumptions are made:The reservoir is horizontal, homogeneous, anisotropic, and has constant Kx, Ky, Kz permeabilities, thickness H, and porosity Φ. The reservoir is with infinite lateral extension, i.e., the boundaries of the reservoir in the horizontal directions are so far away that the pressure disturbance does not travel far enough to reach the boundaries during the well production.The reservoir pressure is initially constant. The pressure remains constant and equal to the initial value at an infinite distance from the well. The reservoir is bounded by top and bottom impermeable formations.The production occurs through a well of radius Rw, represented in the model by a uniform line sink located at a distance zw from the lower boundary. The length of the well is L.A single-phase fluid, of small and constant compressibility Cf, constant viscosity µ, and formation volume factor B, flows from the reservoir to the well at a constant rate Q. Fluids properties are independent of pressure.

Equations for Horizontal Wells

As Figure 1 shows, the horizontal well is a uniform line sink in 3D space, and the coordinates of the two ends are (-L/2, 0, zw) and (L/2, 0, zw). We suppose the point (xO, 0, zw) is on the well line, and its point convergence intensity (point flow rate) is q. In order to obtain the point convergence pressure of (xO, 0, zw), we have to obtain the basic solution of the partial differential equation below:

Equations (available in full paper)
Hydrogen Sulphide Measurements In SAGD Operations-Part II
Authors: Thim H.F.
Published: March 2010

In a previous paper, a method suitable for the measurement of hydrogen sulphide concentrations in SAGD process streams was described. The method is applicable to measuring hydrogen sulphide, non-condensable gases, and steam in lines or units containing up to 70% steam, and avoids the errors inherent in stain tube and Tutweiler measurements.

This paper describes the extension of the method. It is now possible to modify the method to accommodate steam concentrations as high as 98.5% at one extreme, and very dry gases at the other. In each case, modifications of the original train that are required to obtain accurate data are described.

Procedures for meeting regulatory requirements, such as hydrogen sulphide and sulphur dioxide emission measurements, are also described.

Introduction

In a previous paper, a new method for sampling of produced from SAGD facilities was described(1). The method is capable of accurately measuring hydrogen sulphide concentrations, and was shown to be superior to the commonly used stain tube methods. The latter methods were shown to deviate from true concentrations by as much as an order of magnitude. This deviation is thought to be due to the presence of a high mole fraction of steam in the facilities under test.

The method also gives the mole fraction of steam, and that of the total non-condensable gases. The standard error was calculated to be of the order of 5.3%, provided it was possible to collect a sufficiently large volume of non-condensable gas. The upper limit of the method is reached when the steam mole fraction exceeds 70%. A schematic of the sampling train is shown in Figure 1.

Over the last three years, it became necessary to measure hydrogen sulphide concentrations in SAGD facilities under more extreme conditions. In the first case, a hydrogen sulphide concentration was required for a facility gas containing a mole fraction of steam in excess of 98%. In the second case, the gas in the facility was almost dry. Both cases presented significant challenges to measurement, as described in the following.

Design of Original Sampling Train

In the sampling train shown in Figure 1, all of the steam is forced to condense early in the train, regardless of the quality of the steam. The hydrogen sulphide is chemically trapped in the same location in the train, by use of a copper sulphate solution.

Use is made of the reaction:

Cu2+ + H2S →CuS + 2H+

The content of condensed water after the test is easily measured by weighing both the first impinger and the drying tube, before and after the test. The solution containing the precipitated copper sulphide is then quantitatively recovered from the impinger in the field, and the copper sulphide separated in the laboratory. Chemical dissolution of the separated precipitate then permits analysis of the total amount of copper recovered, and calculation back to the amount of hydrogen sulphide trapped. Correction for the precipitate mass is then made to the water weight.
Reverse Circulation Placement Technique vs. Conventional Placement Technique: A Comparative Study of Cement Job Hydraulics Design
Authors: Kuru E. , Seatter S.
Published: March 2010

Reverse circulation cement placement technique (RCCPT) has been suggested asan alternative for providing proper annular coverage for lost circulationzones. It is generally believed that RCCPT helps minimize the circulationpressure and hence, allows cement placement with no apparent losses.

A basic hydraulic design study is conducted to determine the anticipatedpressure losses during the cement jobs run by using both the RCCPT and theconventional cement circulation placement technique (CCCPT).

Results have shown that, for each design case (i.e., wellbore geometry andthe rheology of cement slurry), there is a critical depth above which theequivalent circulating pressure (ECD) with RCCPT can be higher than ECD with CCCPT. Examples of typical cement job design calculations are provided toillustrate the changing ECDs as a function of depth during both RCCPT and CCCPT.

Introduction

Lost circulation is one of the most common problems encountered whencementing a well. The problem becomes increasingly critical, particularly whencementing fractured formations such as the ones encountered in geothermalwells, and coal bed methane wells, or low fracture gradient zones near sea bedsin offshore wells. Primary cementing of these zones using the conventionalcement circulation placement technique (CCCPT) has been very difficult, evenwith lightweight and foamed cement.

Reverse circulation of cement placement technique (RCCPT) has been offeredas an alternative to eliminate some of the problems experienced when cementingpotential lost circulation zones(1–5).

Marquarie and Brisac(1) reported successful applications of RCCPT in the North-Hassi-Messaoud Field in Algeria. Using RCCPT, they were able to cement aweak Triassic formation above the casing shoe without allowing the plasticclays (above the weak zone) to extrude and salt water to enter the well.

Griffith et al.(2) conducted large scale experimental tests to investigatethe advantages of RCCPT. They have suggested that RCCPT is a viable option tolower equivalent circulating densities during the cementing process. They havealso found that reverse circulation of cement on primary cementation neitherincreases nor decreases the displacement efficiency. Griffith et al.(2) alsooutlined a procedure for a typical reverse circulation cementing operationconducted by coal bed methane producers in the area of Trinidad, CO, in the U.S.
Best Method to Balance Torque Loadings on a Pumping Unit Gearbox
Authors: Rowlan O.L. , Mccoy J.N. , Podio A.L.
Published: March 2010

In general there are three methods available to the operator to determine the net torque loading on a pumping unit's gearbox. Two dynamic methods determine the instantaneous torque throughout the pumping cycle. Method 1 combines the measured surface dynamometer card and calculated torque factors with measured or calculated counterbalance moments from the crank and weights. Method 2 uses measured motor power with motor and drive efficiencies and the pumping unit speed to calculate gearbox torque. The third method combines the counterbalance effect (CBE) with the measured dynamometer loads and the torque factors to compute the net torque on the gearbox. The CBE test is a direct method of determining net gearbox torque at a specific crank position to estimate the maximum counterbalance moment. This static test is where the cranks and counterweights are held level until no upward or downward movement is noticed when the break is released. Field case studies applying all three methods to determining gearbox torque are presented in this paper. The pros and cons of using each method are discussed.

Introduction

The oldest and most common method of artificial lift used in producing oil wells is sucker rod pumping. In the United States and Canada, sucker rod lift is used in over 85% of artificial lift wells. The sucker rod lift system consists of four components:prime mover;pumping unit;counterbalance to the rod loading; and,sucker rods and associated downhole equipment. The function of the pumping unit is to convert the rotary motion of the prime mover to the vertical reciprocating motion of the polished rod. Therole of the prime mover is to furnish the necessary power to drive the system.

To improve efficiency, reduce the size of the prime mover and gearbox, and to load the gearbox more uniformly, the sucker rod pumping mechanism is furnished with some type of counterbalance system, where the counterbalance effect at the polished rod is approximately equal to the buoyant weight of the rods plus half the fluid load on the plunger.

Balanced or Unbalanced Gearbox Loading

For each complete stroke, the net torque load on the gearbox is cyclic, usually having two maximum peaks and two minimum valleys. The peaks occur during the upstroke and the downstroke, and the valleys occur at the top and bottom of the stroke. For balanced operation, the magnitude of the peaks should be approximately equal. Pumping unit manufacturers use various types of counterbalancing and mechanical features to reduce the peak gearbox torque and to smooth out the cyclic effects of the load.

The gearbox is said to be underbalanced or rod heavy if the upstroke peak is greater, whereas the gearbox is said to be overbalanced or weight heavy if the downstroke peak is greater. Since in a rotating system torque and power are directly related, the previous statements can be equally applied to the cyclic nature of the motor power developed during a complete stroke of the pumping unit.
Low Pressure SAGD Operations
Authors: Thimm H.F.
Published: March 2010

In the last few years, there has been increased interest in low pressure SAGD operations, in part, due to the gas over bitumen resource conflict. In an earlier paper, it was predicted that low reservoir steam pressures had the effect of sharply reducing hydrogen sulphide and carbon dioxide production per barrel of oil. Likewise, particularly troublesome scales, such as the magnesium and calcium silicates, were less thermodynamically favoured than at high steam pressures.

Further investigations into the fate of gases in SAGD have been undertaken, especially for the case where the virgin pressure of the reservoir is low. In such cases, the amount of solution gas is limited, and the bitumen at steam zone pressure is often undersaturated with respect to the available methane. The polar gases, hydrogen sulphide and carbon dioxide, on the other hand, are almost entirely produced via dissolution in the produced water. In the low virgin pressure case, the methane is entirely produced via dissolution in bitumen. This contrasts with initial reservoir pressures of, for example, 3,500 kPa, where more than half of the methane is also produced via the produced water. The other major difference is that, in the low virgin pressure case, very little gas is predicted to accumulate in the steam zone.

This paper examines the scaling tendencies of minerals, and the fate and compositions of produced gases in both low pressure SAGD and SAGD in low virgin pressure reservoirs. Use is made of recent advances in gas-liquid solution thermodynamics. The implications of this work include a possible effect on simulation studies for bitumen production, as well as on cap gas production via the produced water. This may also be an equity issue in the Athabasca area where cap gas has been shut in by regulatory intervention.

Introduction

There has been considerable interest in the issue of SAGD steam zone pressure (or temperature) in recent years. The issue revolves around the range of pressures under which a given SAGD project might be operated, without serious adverse economic effects on the project. Chhina(1) is reported to have advocated the use of lower pressures in order to reduce steam-oil ratios (SOR), and therefore production costs. The issue has been further explored by Kisman(2), who defines low pressure SAGD as involving "pressures below what steam/gas lift can accommodate, and above pressures where low-pressure consequences, such as reduced oil rates and artificial lift difficulties, affect the viability of SAGD operations." One of Kisman's conclusions was that operation at reasonably low pressures provides savings due to reduced SOR, and the smaller production well liners and tubulars that are needed. While there are limited field data on low pressure SAGD at present, the issue has received more detailed attention in the last few months owing to the ongoing gas-bitumen resource conflict.

A previous paper(3) explored a number of aspects of the engineering chemistry of SAGD, which are also dependent on the pressure (i.e., temperature) of the steam zone.
The Importance of Comprehensive Gas Field Surveillance
Authors: Baker Richard
Published: March 2010

Outline of Problem

Gas field surveillance historically has not been given the same priority as oil field surveillance because of a couple of significant stumbling blocks: first, the apparent simplicity of gas reservoirs- at least upon initial examination; and, second, the historically low commodity prices of gas relative to oil. The presumption that gasfield surveillance was easily derived from the knowledge that, in most gas pools, single phase flow existed, leading to the assumption that "tank like" behaviour was occurring. However, on examination of hundreds of gas pools, my viewpoint on that matter has changed dramatically. Of course, today's commodity prices are also changing both the relative and absolute perceptions about the economic importance of gas.

Initially, in the Western Canadian Sedimentary Basin (WCSB), industry encountered and dealt with very high quality gas resources, such as those found in Leduc reservoirs. These reservoirs had high permeability and were not compartmentalized; this naturally led to the "tank model" approach. These pools had behaviour as illustrated by Figure 1(a). In the last few years, we have moved from what I would term "Tier One" resources to lower quality ones, as shown in Figure 2.

Indeed, a large portion of reservoirs do not exhibit that "tank like" behaviour shown in Figure 1(a); instead, there is often a fairly large pressure gradient across pools and non-tank like behaviour, such as that shown in Figure 1(b). This paper stresses the importance of comprehensive surveillance for those types of fields, using simple methods of production analysis and pressure diagnostic tools.

There has been an explosion of research on using gas rate decline methods to characterize reservoirs with an effective permeability less than 0.1 mD (k < 0.1mD). However, the transient gas rate decline and practical analysis of such low permeability gas reservoirs are not the focus of this paper. This paper instead focuses on gas field surveillance for multi-well pools in which wells are in boundary dominated flow.

The objectives of any gas surveillance program are relatively simple:What is the Original Gas in Place (OGIP)?;What is the current gas in place?;Where is the current gas in place located?;What is the permeability or capacity (kh) of the wells and pool?;What are the limiting considerations to gas recovery factor (low permeability, liquid lifting problems, low continuity, high back pressure, or water influx)?;What can be done to improve the rate of recovery and the recovery factor? and,Can this be done economically?

In order to understand the above questions, we must relate the static model (geological/petrophysical) to the dynamic (production/ pressure data) one.

Surveillance Methodology

The following work flow has proven to be useful in determining the true potential of gas reservoirs:Examine the production profile of individual wells and the field. Examine the initial production rates (IP), interference effects, types of decline, and decline rates (production diagnostics);
A New Technique to Measure the Breakthrough Capillary Pressure
Authors: Smith J.D. , Chatzis I. , Ioannidis M.A.
Published: March 2010

The breakthrough capillary pressure is an important macroscopic property of porous media that is used to predict permeability and to correlate capillary pressure curves. It is normally determined using the porous plate method, where the non-wetting phase is introduced into the medium in increasing steps of pressure until it establishes a continuous pathway through the sample. In mercury porosimetry, breakthrough capillary pressure is identified as the pressure corresponding to about 10 - 20% non-wetting phase saturation or the point of inflection in the drainage capillary pressure curve. A new method for measuring the breakthrough capillary pressure has been developed, involving a constant rate injection process as opposed to constant injection pressure. The scope of this paper is to report the accuracy and reliability of the new technique in measuring the breakthrough capillary pressure by reporting test results on transparent micromodels and Berea sandstone core samples. Air or mercury was used as the non-wetting phase while water (or brine, in the case of core samples) was the wetting phase. Constant rate injection was provided by means of a syringe pump, using water to displace a slug of either air or mercury in a tube connected to the porous medium at rates of about 1.8 × 10−2 cm3/min. Pressure was measured at the sample inlet using a pressure transducer and data were recorded using a data acquisition system. The injection pressure vs. time plot reveals the highest pressure established in such a test, which is identified as the breakthrough capillary pressure. It was concluded that the new test enables the determination of the breakthrough capillary pressure in micromodels with excellent accuracy. The new test was also validated using a sandstone core sample.

Introduction

In the literature of immiscible displacement in porous media, the terms "breakthrough capillary pressure," "threshold pressure," "entry pressure," and "bubbling pressure" are frequently encountered. It has been observed, for example, that in order to make a non-wetting phase, such as air, flow through a porous medium saturated with brine, the applied capillary pressure on the air side has to exceed a critical limiting value, Pc °, at which air can flow through the medium (i.e., can break through and emerge as bubbles from the outlet face of the sample). The pore channels in the medium used by the air to break through the sample are made up of pore sizes greater than or equal to the pore size De °, defined by

Equation (Available In Full Paper)

Where γ is the interfacial tension, θ is the contact angle, and De ° is the (equivalent) diameter of a capillary tube of circular cross-section which requires the same capillary pressure, Pc °, for penetration as that measured at breakthrough capillary pressure in the porous medium. The value of De ° calculated using Equation (1) is the minimum capillary size that is necessary for the non-wetting phase to invade and break through the medium.
Dual Gas Lift in Wells With Downhole Water Sink Completions
Authors: Marcano L. , Wojtanowicz A.K.
Published: March 2010

Downhole Water Sink (DWS) technology controls water coning in dual-completed wells by concurrently producing water from the bottom completion below the oil-water contact, and oil from another completion at the top of the oil sand. It has been shown that DWS improves well productivity, increases oil recovery, and could produce oil-free water for direct injection or overboard dumping offshore. To date, DWS has been applied in natural flow wells or wells where a downhole pump can be easily installed. However, in many areas, such as the Louisiana Gulf Coast and Venezuela where water coning is commonplace, the only production method is gas lift.

This paper presents a feasibility study and a design method for dual gas lifting in DWS wells. The design employs a two-tier nodal analysis for several combinations of two tubing strings- one for oil and a second one for water-installed in a production casing. First, nodal analysis is performed separately for the water and oil legs in order to define their operational range. Then, the two solutions are combined and coupled with the Inflow Performance Window (IPW) describing the operational domain (top inflow rate vs. bottom inflow rate) of the well.

Using the new method, a simulation study was conducted using data from actual wells. The results indicate that the gas lift would limit the performance of DWS wells. Moreover, the design can be optimized for maximum production of oil with controlled water withdrawal from the bottom completion. Limitations such as maximum gas injection rate, or injection gas pressure, are discussed. Also, this paper presents an example of a theoretical performance of a DWS well with gas lift.

Dual Gas Lift-State of the Art

Gas lift is a flexible method. It is possible to use it in wells of 0.159 m3 (a few barrels) per day, or wells of 159 m3 (a thousand barrels) per day. There are several methods of producing hydrocarbons using gas lift, but continuous gas lift is most common. Presently, there are at least 1,500 wells in Venezuela producing by intermittent gas lift. Also, single well completions are the most used gas lift installations around the world.

For any type of gas lift method, there is a maximum production rate, which is a function of depth, reservoir, completion, and surface conditions. This maximum production requires a specific optimized rate of gas injection. Any additional gas injection rate would result in an oil production rate smaller than the maximum rate.

To optimize gas lift for a given well, which includes the selection of tubing strings, size limitations, and maximum available gas flow rate, it is necessary to find the best depth of injection point and the gas injection pressure.

Although dual gas lift has been theoretically developed, it has not been practiced very much since single well completions are most commonly used around the world. In fact, only a few field cases of dual gas lift have been reported in the literature(1–8).
Comparison of Correlations for Viscosity of Sour Natural Gas
Authors: Jeje O. , Mattar L.
Published: March 2010

There are two commonly used correlations for determining the viscosity of natural gases. These are the Carr, Kobayashi, and Burrows (CKB) and the Lee, Gonzalez, and Eakin (LGE). The CKB applies to both sweet and sour gas, but the LGE was derived purely for sweet gas. The CKB is a graphical correlation, and consists of two sets of graphs with temperature as the correlating parameter (not easily adaptable for computer applications). On the other hand, the LGE is a set of simple equations, and therefore can be easily programmed for a computer. The LGE is used in numerous computer programs, with no regard to the fact that it was not derived for sour gas.

This study compares the LGE to the CKB graphs for both sweet and sour gases. A detailed comparison of the two methods using various gas mixture compositions, temperatures, and pressures was conducted. The results illustrate that for sweet gases, the comparison is acceptable, and the LGE equation can be used for most reservoir engineering purposes. However, for sour gases, the differences between the LGE and CKB correlations can be significant. This leads to the conclusion that the LGE correlation, which was derived for sweet gases only, should not be indiscriminately applied to sour gases.

Introduction

Gas viscosity is used in several calculations dealing with fluid flow and reservoir behaviour. Empirical correlations have been developed to estimate values for viscosity over a range of pressures. Most viscosity correlations are either equation based or in a graphical form derived from laboratory measurements. Typically the correlations are functions of temperature, pressure, gas gravity, and composition. Often they are paired with various corrections for non-hydrocarbon components. Applying a correlation without corrections to a sour gas case can lead to large errors in predicting viscosity.

Carr, Kobayashi, and Burrows Correlation

The Carr et al. correlation (henceforth referred to as CKB) was developed to predict the viscosity of gas hydrocarbon mixtures over a large pressure and temperature range. The limits of the correlation are temperatures between 32 and 400 °F and reduced pressures up to 20 (which can equate to pressures higher than 12,000 psia). It was designed to handle non-hydrocarbon components CO2, N2, H2 S) in concentrations of up to 15% each.

Calculation of viscosity with the CKB method is a three-step process based on graphical methods. The first step is to determine the viscosity at atmospheric pressure based on the gas gravity and temperature using Figure 1.

Next, corrections are added to the viscosity based on the H2S, CO2, and/or N2 content of the gas. Finally, the viscosity is multiplied by a ratio based on the reduced pressure from Figure 2.

The only disadvantage of the CKB method is that it is based on several charts, making it difficult to program into a computer. Two methods that have been used to simplify computation have been to generate a series of polynomial curve-fits or to use a table lookupinterpolation scheme(1)
Experimental Study of a Novel In Situ Gasification Technique for Improved Oil Recovery From Light Oil Reservoirs
Authors: Greaves M. , Xia T.X. , Rathbone R.R. , Bentaher A.H.
Published: March 2010

In situ gasification of crude oil using downhole gasification (DHG) is a new, improved oil recovery technique for application in light oil reservoirs. Inert gas is generated inside a DHG unit by gasifying part of the produced oil. A string of DHG units is positioned along a horizontal producer well, or on a vertical well. The gases, mainly hydrogen and CO2, are then directed into a gas cap formation. Incremental oil recovery is achieved via gravity stabilized gas injection (GSGI) or another suitable gas displacement drive method. There is essentially no net heat release into the reservoir if efficient heat recovery is practiced.

A series of high pressure, continuous flow experiments was performed in a small-scale gasifier unit, using n-pentane as feedstock, to represent the light naphtha fraction from a crude oil. The experiments were operated at pressures up to 100 bar, compared to the 20 to 30 bar normally used in a surface steam reforming plant. Catalytic steam reforming of the pseudo-light naphtha fraction, containing reservoir gas, achieved conversions of 70 to 80% at a gasifier exit temperature of 720 °C. The produced gas contained up to 50% hydrogen, with the remainder comprising carbon oxides.

The new IOR technique has wide potential application in depleted light oil reservoirs where the pressure is less than about 200 bar, although it may be possible to increase this limit. The economics of the DHG process appear to be attractive, if energy is recovered from the hot gas stream. The produced gases are stored-up in the reservoir and any emissions are therefore limited to those which are released from the crude oil when it is produced. If the reservoir pressure is low, then the amount of gas produced with the oil will be relatively small. The hydrogen product storedup in the reservoir is a valuable resource, which could be recovered later for use in the future "hydrogen economy."

Introduction

Previous attempts to increase oil recovery from (mainly) heavy oil reservoirs by introducing a source of heat have focused on heating up part of the reservoir. Thus, Niles(1) proposed using an electrical heater to heat part of the oil formation so that the oil was partially vapourized in order to increase the reservoir pressure. It was also claimed that the oil viscosity was reduced, thereby increasing the flow of the oil. This was probably only a marginal effect because there is no permanent overall reduction in the crude oil viscosity. Nielsen(2) proposed a method of heating shale oil layers by pumping hot gases into the reservoir matrix to pyrolyse the oil or kerogen material. The vapourized fractions were then collected at the surface.

The new underground gasification, or DHG technique, first proposed by Davidson and Yule(3), differs from all other previous attempts in one major respect. Heat is provided electrically inside a DHG unit so that there is no direct contact with the reservoir matrix.
Rate Dependence of Transient Linear Flow in Tight Gas Wells
Authors: Ibrahim M. , Wattenbarger R.A.
Published: March 2010

Many tight gas wells (permeability less than 0.1 mD) exhibit transient linear flow; sometimes for several years. This behaviour differs from radial flow in many ways. This paper reports another import difference between linear flow and radial flow? rate sensitivity.

It has been shown and accepted for years that real gas pseudopressure can be used to apply analytical solutions to transient radial flow. However, it has been noticed that analytical solutions can be in serious error when applied to transient linear flow. Specifically, the slope of the √t plot departs from the analytical value as the flow rates or degree of drawdown becomes higher.

This paper demonstrates the rate/drawdown sensitivity of transient linear flow. Then a correction factor is presented which corrects the slope of the plot and improves the accuracy of √k Ac and OGIP, as calculated from production/pressure performance.

Introduction

Many wells in tight gas reservoirs have long-term performance which exhibit only linear flow, not radial flow, during the transient period. Wells have been observed which stay in the transient linear flow regime for several years. Some of these wells have hydraulic fractures and some do not. It is usually not practical to analyze tight gas wells with build-up tests, but long-term production and pressure data can be used for analysis. Previous papers have presented methods of analysis(1–5).

The analysis of these wells comes from plotting [m(pi) - m(pwf)]/ Qg vs. √t and observing the slope, mCPL, and the end of the straight line, tesr (end of the transient linear flow period). From these values, √k Ac and OGIP can be calculated.

It has long been accepted that radial flow transient solutions can be approximated by analytical solutions, in terms of m(p), regardless of flow rate. Constant rate solutions have been emphasized, but it can also be shown that constant pwf flow can also be approximated by analytical solutions, regardless of the level of drawdown(5).

The drawdown/rate dependency linear flow is different than analysis of radial flow. This difference was demonstrated with reservoir simulation in this work. A correction method was developed to improve the accuracy of analysis of transient linear flow for analyzing tight gas wells.

Effect of Drawdown on Transient Linear Flow (Constant pwf)

A number of transient linear flow cases were run with constant Pwf. It was found that these cases did not have the same slopes as the analytical solution, but varied according to the level of drawdown. In order to demonstrate this effect, a dimensionless drawdown parameter is defined as follows:

Equation (Available In Full Paper)

Some results are plotted in Figure 1. It can be seen that the slope of these plots is greatly affected by the level of drawdown, DD. As the drawdown value increases, the slope (mCPL) value decreases. Since the analysis equations(5) are based on analytical solutions, the calculations may be wrong when actual data is analyzed.
Optimization of Solvent Aided Process
Authors: Gupta S. , Gittins S.
Published: March 2010

The Solvent Aided Process (SAP), described previously by the authors, is an improvement to SAGD that promises to enhance the economics of bitumen/heavy oil recovery projects and reduce water usage.

In SAP, a small amount of hydrocarbon solvent (such as a low molecular weight alkane) is introduced as an additive to the injected steam during SAGD. The viscosity of the oil is reduced due to solvent dilution in addition to heating. SAP holds the promise of significantly improving the energy efficiency of SAGD, thus, reducing the heat requirement. Encana's field trials of SAP, discussed elsewhere, have shown the practical upside of this process. This paper discusses two conceptual optimizations of SAP.

SAP reduces the effective steam-oil ratio (SOR) of SAGD. However, this comes at a cost as a part of the injected solvent is retained in the reservoir and lost in terms of economics. The smaller this cost is, the better are the economics of SAP. In this paper, the merits and drawbacks of using two alternate substances, SO2 and olefinated light alkanes, as solvents are discussed.

Bottom-up SAP is a special geometrical configuration of SAP, discussed before. In this variant of the SAP process, bitumen recovery progresses from the bottom to the top of the reservoir, and employs injector and producer wells that are spaced horizontally apart rather than being in the same vertical plane. For large horizontal spacing between the injector and producer in a well pair, rates are low. On the other hand, for small spacing, the capital associated with the project is high. This paper explores the optimal horizontal spacing between the wells in a bottom-up SAP well pair.

Introduction

Steam-Assisted Gravity Drainage (SAGD) relies primarily on heat supplied to the reservoir by steam to reduce the viscosity of the oil(1). In SAP(2–5), solvent dilution is also taken advantage of to aid in this viscosity reduction. The result is an enhanced rate of oil production and recovery leading to superior economics with lower energy intensity and a reduction in water usage. To further improve the economics and energy efficiency of the process, in this paper, two optimizations of SAP are discussed; namely, employment of inexpensive solvents and optimal configuration of bottom-up SAP.

SAP economics depend on the extent of the residual solvent in the reservoir(3) such that, the higher the inventory and cost of the unrecovered solvent, the less advantageous it is to carry out SAP. In principle, any of the commercially-available light alkanes (e.g. propane, butane or natural gas condensate) can be employed for SAP. However, these liquids tend to be expensive due to their multiple uses in the industry and their price generally varies in sync with light sweet crude. This fact naturally offers an opportunity to further improve the economics of SAP by looking for other solvents, and the discussion below describes two such alternative, inexpensive solvents.
Advances in Magnetic Resonance Relaxometry for Heavy Oil and Bitumen Characterization
Authors: Kantzas A.
Published: March 2010

This paper offers a summary of the advances in heavy oil and bitumen reservoir characterization and fluid stream monitoring using low field magnetic resonance tools. Both laboratory and field advances are presented. Although the bulk of the work discussed was performed in our laboratory, a selection of other pertinent technologies is also presented. This overview aims at offering the reader a quick reference of what has been achieved in the past ten years and it is hoped that it will be used as a guide for future development in this area.

Introduction

Low field nuclear magnetic resonance (NMR) relaxometry is a technology that offers significant benefits in reservoir characterization through the magnetic resonance logging tools that are offered by oil and gas service companies(1). These tools can offer measurements of porosity, permeability, mobile and bound fluids and, potentially saturations, if they are properly calibrated. This technology has been active in its latest reincarnation since the middle of the 1980s. It was originally developed with conventional oil and gas reservoirs in Texas and the North Sea. There are currently several excellent reviews and two recommended books for those interested in studying the topic in detail(1–4).

Through low field NMR we measure the amount of and the mobility of hydrogen-bearing molecules. For reservoir characterization applications, such molecules translate into gas, water or oil present within a formation. Although the physics of the process are not the focus of this overview, a brief introductory summary is included. For details, the reader is directed to the references above.

The measured parameters in NMR are amplitudes of hydrogenbearing signal and relaxation times of hydrogen-bearing molecules. The amplitude is directly proportional to the amount of protons present and it can be correlated to the volume or mass of fluids within the region of measurement. The relaxation time is affected by the relative mobility of the hydrogen-bearing molecules. Thus, as visocsity increases, or the surroundings of the relaxing hydrogen are restricted, then relaxation occurs faster. There are two relaxation times that can be measured: longitudinal (T1) and transverse (T2). The focus of our work deals with transverse relaxation phenomena.

Figure 1 is used as the typical figure to explain different types of relaxation spectra obtained when exposing different systems in the standard pulse sequence that is used in logging and laboratory tools alike. The spectrum of bulk water (i.e. water in a beaker) is a simple narrow peak that shows relaxation at T2 of ~2,500 ms. Compared to water, bulk bitumen (viscosity of ~1,000,000 mPas at room temperature) typically relaxes with a broader peak at less than 2 ms. Thus, in principle, a beaker that is half-full of water and half-full of bitumen would show two peaks, as shown in Figure 2.

Figure 1,2,3,4 (available in full paper)

In this case, the oil is somewhat lighter than that of Figure 1 (viscosity of ~100,000 mPas at room temperature).