bluuebunny/crossref_metadata_2025 huggingface dataset:
Monitoring The Performance Of Pembina Nisku Miscible Floods
Authors: Bennett F. , Geoghegan J.G.
Published: March 2010

Esso Resources Canada Ltd. operates gravity-stable hydrocarbon miscible floods in seven Pembina Nisku pinnacle reefs. All these floods were started between 1982 and 1985 and recovery from the more mature floods has exceeded 50% of original-oil-in-place (OOIP), During 1989 a number of infill wells were drilled to maintain productivity and reduce solvent coning. Open hole gradiomanometer logs were run in these wells to determine gas, solvent, oil and water contacts. Previous cased hole contact logging had been unsuccessful and these infill wells afforded an opportunity to assess the progress of the miscible floods with open hole contact logs.

This paper reviews the performance of the miscible floods and describes the results of the contact logging, The implications of the contact log results are discussed in regard to solvent bank dispersion, volumetric conformance and displacement efficiency, and future infill drilling and completion strategy.

Introduction

Sequence of Development

The Pembina Nisku pinnacle reefs are located approximately 160 km southwest of Edmonton. Figure 1 shows the 17 Esso working interest pools in the area of which eight are waterfloods and nine are vertical miscible floods. Esso operates seven of the miscible floods.

The Pembina Nisku G and K pools were the first pools to be miscibly flooded. After primary depletion to the bubble point pressure (between 1978 and 1979) the pools were shut in until 1981, when facilities were in place to commence miscible flooding. As shown in Table 1, the cumulative recovery to date (1989 year-end) is 56% and 50% of OOIP for the G and K pools, respectively.

The Pembina Nisku O and P pools followed with miscible flood start up in 1983. These pools have produced 40% and 44% of their respective OOIPs to date.

M pool was a Getty Oil pool, later acquired by Texaco, which also started miscible flooding in 1983. It has a recovery to date of 48% of OOIP.

Pressure maintenance in the largest of the Nisku pools, the L pool, began in 1981 with a waterflood. At that time there was a concern that a Cynthia shale tongue between the Upper and Lower Zeta Lake reef portions might be widespread laterally and disturb the solvent bank integrity in a miscible flood.. Subsequent infill drilling showed that the shale was localized in the region of the two southernmost wells. Consequently, waterflooding was suspended in 1985 and a miscible flood was started. Production of injected water also commenced that year as pan 0 f a scheme to recover residual oil in the water flushed zone.

The Q pool also began miscible flooding in 1985. The cumulative production for the L and Q pools is 48% and 36% of their respective OOIPs.

Prior to 1989 production was primarily constrained by market demands, the provincial allowable or Energy Resources Conservation Board (ERCB) maximum rate limitation (MRL) rates. In 1988 and 1989, solvent coning in wells completed at the base of porosity made it necessary to drill additional infill wells to reduce drawdowns and maintain pool productivity.
Characterization Of Formation Damage By Particulate Processes
Authors: Millán Arcia Einstein , Civan F.
Published: March 2010

A model-assisted analysis of formation damage in the S and S3 facies of the Eocene B-Inferior formation in Ceuta field, Lake Maracaibo, western Venezuela, is carried out. The governing mechanisms and the estimated values of the phenomenological rate constants are determined using the formation damage model by Ohen and Ciyan. A skin factor chart is constructed based on this information as a practical measure of the formation damage potential.

Introduction

Reduction of injectivity of wells by formation damage can be of considerable magnitude during waterflooding of oil reservoirs. The origin of formation damage can be of chemical and mechanical caused by interaction between porous media and fluid flowing through it. Chemical damage occurs due to the incompatibility between the constituents of mineral rock and the flowing fluids. Mechanical damage can he caused either by external particle invasion, as in the case of suspended particles in completion fluids, or internal particle movement mainly influenced by hydrodynamic forces. Variation of pH of the flowing fluid is an indicator of the extent of chemical activity occurring in the formation. Dissolution of cementing - authigenic materials such as carbonates and/or ion exchange between fluid and minerals can cause pH variation, High pH (alkaline media) promotes formation damage by particle deposition within the porous media and consequently particle bridging at the pore throats. Occasionally, the particle bridges brake causing temporary permeability increase. This is reflected by the pulsating character of the pressure differential and permeability reduction data. Permeability reduction and skin factor are used as quantitative measures of formation damage. A detailed description of the processes involving formation damage of porous media is given in the literature(l-14).

This paper presents a model-assisted anaIy;is of formation damage in sandstone core samples belonging to the facies S and S3 of the Eocene B-Inferior formation, in Ceuta field, Lake Maracaibo, western Venezuela. The details of this study are given by Millan(l5) Due to the high content of carbonaceous and siliceous type authigenic materials the Ceuta field core samples are extremely sensitive to brine, rendering the pH toward alkaline media during waterflooding. As a result particles tend to disperse to reduce the formation permeability. Permeability alteration process is numerically reproduced by means of the Ohen and Civan model(l2) and extended beyond the experimental range. The values of the phenomenological rate constants involving the hydrodynamic and electrochemical processes, which controls the trapping and/or release of particles within the porous media, are determined and a skin factor chart is constructed using the Ohen and Civan method(13).
Non-Newtonian Effects On The Primary Production Of Heavy Oil Reservoirs
Authors: Poon D. , Kisman K.
Published: March 2010

A number of heavy oil and oil sand reservoirs in Alberta have been successfully produced by natural depletion at rates far in excess of the predictions based on radial Darcy flow. Production rates can exceed 20 m3/d and con be maintained at such a high level for several years. What exactly causes the high primary production rates is not known, but several mechanisms on the primary production of heavy oil and bitumen have been proposed by various authors. These include solution gas drive, influx of bottomwater, sand production, wormholes, fractures and channels. Laboratory measurements which have been reported on the rheological properties of bitumen indicate that at low temperatures (e.g. 20 °Cj a mixture of bitumen or heavy oil with a small amount of sand behaves as a non-Newtonian fluid. The flow characteristics of a non Newtonian fluid in a reservoir and their effects on the primary production of heavy oil have been investigated in this study using ana/ysica/ solutions of the diffusivity equation. It was found that di/atant (shear thickening) effects can provide an explanation for low apparent viscosities at a distance from the wellbore where shear rates are low. This mechanism is consistent with the pressure buildup test results and with field production data where high production rates can be sustained over an extended period of time.

Introduction

A number of heavy oil and oil sand reservoirs in Alberta and Saskatchewan have been successfully produced by natural depletion. Primary recovery at the Lloydminster heavy oil deposit, which began over 40 years ago, has been significantly higher than the predictions based on radical Darcy flow. The heavy oil deposits in this area are relatively thin (3 m to 6 m) and occurring at depths from 300 m to 1000 m. The formations consist of unconsolidated sands with a relatively high porosity (29% to 35%) and high permeability (3500 mD). The oil gravity is quite low ranging from 10 to 20 degrees API with an oil viscosity of 400 mPa.s to 2000 mPa.s at initial reservoir conditions.

Since 1985, Amoco have been producing significant amounts of bitumen from the Lindbergh Elk Point(1) area on primary production. The Clearwater formation at this location is 25 m to 30 m thick and consists of a moderately well sorted sand. The bitumen has a gravity of about 12 degrees API and a very high viscosity of 60 000 mPa.s at reservoir conditions (3900 kPa and 2O °C). The primary production rates average 15 m3/day 00 20 m3/day for over 3 years. These production rates are greater than can be predicted with radial Darcy flow calculations by a factor of more than 30.

Potential Mechanisms

It is not known what exactly causes these high primary production rates but a number of potential mechanisms have been suggested. in the literature: solution gas drive; influx of bottomwater; sand production; wormholes, fractures and channels; and rock compressibility.

Smith(2) suggested that a possible production mechanism could be solution gas drive which was assisted occasionally by the influx of water.
"Honey, I Shrunk the Pores!"
Authors: Beliveau Dennis
Published: March 2010

Introduction

When I was young, my parents instilled in me a curiosity about the physical nature of the world. I remember Dad, an avid reader of "The Country Guide," explaining the enormous power or a prairie thunderstorm by telling me "an inch of rainfall on all acre of land is over one hundred tons of water." To bring this analogy closer to our own business, it still amazes me that a reservoir one foot thick with ten per cent porosity will also hold almost one hundred tons of oil per acre of land. Sometimes we get so bogged down by the details of our business, we don't have time to think about some of nature's simple wonders.

With thoughts like these in mind, it's neat to take a closer look at a parameter which is taken very much for granted: porosity. To ost of us, the only thing which matters is the absolute value of porosity, and obviously the higher the better! Some interestinghenomena pop to light, however, when one really visualizes things on a pore-scale. With that in mind, let's take closer look at some porous systems from the inside...

Conventional Pore Systems

Let's quickly review some basic geometric concepts, focussing at the pore-scale. Table 1 shows how Archie(1) and Lucia(2) classified carbonate pore sizes: a typical "medium"-sized pore is about 50 microns (0.002 inches). Pore throats, the inter-pore connections which determine permeability, are much smaller, often in the 1-10 micron range. Obviously, it takes an enormous number of these pores to form a reservoir. We also know that the size of the individual pores may not have much impact on the total porosity. Figure 1 shows the porosity resulting from a cubic arrangement of spherical grains is 48%, regardless of the size of the grains.owever, for a given porosity, the pore system surface area increases as the average pore size decreases (Table 2).

The surface areas in Table 2 assume pores are spherical: however, in reality their shapes are much more complex. As a result, urface areas in reservoir rocks may be 100 times higher than shown in Table 2 due to tile dramatic effects of surface roughness.good example is Donaldson's work(3), which showed the

TABLE 1: Pore size classifications. Table Available In Full Paper.

TABLE 2: Ways to make 11% porosity in 1 m3 of rock. Table Available In Full Paper.

surface area of many common reservoir rocks to be about 1 m2/gm.

These large surface areas are rather startling at first glance.

Imagine one cubic metre or oil-saturated rock with 11% porosity. Table 2 shows the resulting 0.11 m3 of oil would be spread over 10,000m2; accounting for pore surface roughness the area would actually be about 1,000,000 m2. To put it in more real terms, this would be like spreading a couple of cups of oil across the surface of a foothall field. Is it any wonder that oilfield recoveries average only about 25%?
Numerical Simulation of Electromagnetic Heating of Alaskan Tar Sands Using Horizontal Wells
Authors: Wadadar S.S. , Islam M.R.
Published: March 2010

In an effort to develop a novel recovery technique for tar sand reservoirs of Ugnu in Alaska, electromagnetic heating using horizontal wells is proposed. One of the bigger technical problems with thermal injection on the North Slope is the large permafrost region. The permafrost reduces the effective heat that can be transmitted to a reservoir, even with insulated tubing. Applying the heat with a down-hole device, such as electromagnetic heating is a much more efficient process than conventional thermal recovery techniques. The horizontal well addresses another problem by heating and producing from the same well bore. The drainage radius is normally very limited due to the inability to conduct or convert heat away from the wellbore. A horizontal well, particularly one located at the bottom of a thick sand with vertical permeability, allows gravity drainage of a much larger reservoir volume. This paper presents numerical simulation results of such a process for Alaskan tar sand reservoirs using a horizontal well simulator. Numerical simulation results show oil recovery as high as 40% of the oil in place for tar sands. The recovery is even higher for heavy oil of moderate viscosity.

Introduction

The state of Alaska is estimated to contain some 70 billion barrels of oil in place. More than 50% of this reserve is in the form of heavy oil and tar sand in the Alaskan North Slope(1). Some 15 billion barrels of this reserve is in the form of tar sand in the Ugnu reservoir of the North Slope.

With recent decline in oil production from the Prudhoe Bay light oil reservoir, there is a need to develop techniques for expanding oil production from other oil resources of Alaska. One such reservoir is the tar sand of Ugnu.

Oil in the Ugnu reservoir was discovered by BP in the eastern region in the range of 828–994 m depth. Ever since the original discovery, there have been several drilling activities in the area during the 1970's. The Ugnu sand is divided into a lower and an upper zone. Figure 1 shows a cross sectional view of Ugnu and West Sak reservoirs. The lower Ugnu is mainly medium grained ranging from fine to coarse grained. The thickness of the lower Ugnu ranges from 75 to 92 m tbroughom most part of the northern Kuparak area. There are three to five major sand beds in the lower Ugnu interbedded with silts and muds. However, sand beds range from 3.5–10 m at the base to 20–31 m thick at the top of the member. The lower Ugnu is separated from underlying West Sak sands by a regionally extensive shale and mud sequence.

FIGURE 1: Cross-sectional view of Ugnu and West Sak. (Available in full paper)

The upper Ugnu sands are thicker than lower Ugnu sands and are mainly fine to medium grained. The upper Ugnu has an average thickness of 100 m in the Kuparak area and is composed of five to seven major sand beds. Each sand bed has an average thickness of 10–20 m.
Theoretical Analysis Of Miscible Displacement In Fractured Porous Media By A One-Dimensional Model: Part I -- Theory
Authors: Tan C.T. , Firoozabadi A.
Published: March 2010

A one-dimensional model is formulated to describe miscible displacement in fractured porous media. Four parameters, R1 (normalized fracture capacity), B (productivity capacity ratio), M (viscosity ratio), and Ngr (gravity number) that characterize the process are identified. No-crossflow and crossflow equilibrium assumptions are made, and solution methods for both cases are provided. In the case of crossflow equilibrium, the flow is balanced by the viscous and gravity forces. Three branches of solution characteristics are discovered. These are:dominant viscous crossflow,moderate gravity crossflow, andstrong gravity crossflow. The criterion for each case is given in terms of viscosity ratio and gravity number.

Depending on the magnitude of viscosity ratio and gravity number, crossflow direction changes along the length of matrix-fracture interface.

Introduction

One of the main characteristics of a fractured petroleum reservoiris high rate wells in the early life of the field. Depending on the drainage rate. the high rate can continue for a long time for some fractured reservoirs and for a very short period for others, Fractures increase the effective single phase permeability of the combined matrix-fracture porous media. The magnitude of the increase of effective single phase permeability depends on the (kA)r/(kA)m ratio (fractures are assumed perpendicular to the well). For most naturally fractured reservoirs, (kA)r/(kA)m is in the range of 10 to 100. Therefore, wells could produce at rates of 10 to 100 times more than a nonfractured matrix. The above picture of a fractured petroleum reservoir changes for the two phase gas-oil now process. The oil drained from the matrix to the fracture could partly or totally reinfiltrate to the blocks underneath due to capillary and gravity forces(1,2). The reinfiltration process, therefore, substantially reduces the rate of oil production in the two-phase gas-oil region. Another parameter which could lower the rate of drainage in fractured porous media is the fracture gasoil capillary pressure. Visual observations have revealed that the oil now in the fractures for the gas-oil immiscible system is mainly film now, and higher fracture aperture (i.e., fracture capillary pressure effect) reduces the liquid film flow across the matrix blocks(3). Both the reinfiltration process and the capillary pressure contrast between the matrix and fracture lower the rate of drainage. In other words, the rate of drainage from fractured porous media, when the oil is derived from the matrix. is less than in an unfractured medium with the same matrix permeability, provided oil compressibility effects and fracture storage are negligible. After an infinite lime period due to capillary continuity, the ultimate recovery will be the same for both fractured and unfractured porous media.

The key to drainage rate enhancement for fractured porous media is:to increase gas-oil gravity drainage rate, andto reduce rein filtration rate.
Managing Hydrocarbon Injectionat At Judy Creek
Authors: Lloyd C.J.
Published: March 2010

Tile Judy Creek Beaverhill Lake ‘A’ and ‘B’ Pools have been undergoing pattern hydrocarbon miscible flood (HCMF) since 1985 and 1987 respectively. This paper describes the evolution of the hydrocarbon injection strategy for the Judy Creek Pools from 1985 to today.

The original HCMF design for each pattern was a water-alternating- gas (WAG) ratio of 1.0. minimum solvent bank of 15% of the continuous hydrocarbon pore volume (CHCPV), and a minimum chase gas bank of 20% of the CHCPV. Analysis of performance data has resulted in an evolution of HCMF design parameters and operating strategy, injection strategy is now specific to each pattern and zone. Downhole isolation equipment has been used extensively to improve zonal control leading to better reservoir sweep: examples of this are presented. Both ofthese changes have significantly improved tertiary recovery, but also have greatly increased the data management required. Imperial Oil's current method of designing, scheduling, and reporting hydrocarbon injection banks and WAG ratios by pattern and geologic zone is discussed. This includes a computer program that has been developed to calculate pattern and zonal hydrocarbon banks and WAG ratios.

Approximately 1,400 103m3/d (50 mmcf/d) of hydrocarbon is injected into the Judy Creek HCMF3. Optimal use of injectant is a key lever in maximizing profitability of these hydrocarbon miscible floods.

Introduction

The Judy Creek "A" and "B" Pools are located about 200 km northwest of Edunonton. Alberta, and were both discovered in 1959. Figure 1 is a gross thickness of 70m (230 ft). The "B" pool is geologically similar but smaller its original oil in place is estimated at 39.8x 106 m3 (250 MMSTB) and it covers an area of 4.915 ha (12,000 acres). Examples from both pools have been included, but the paper will focus on the "A" pool.

Geologically, the "A" Pool is an atoll-like reefal limestone. It can be generally described as a highly porous organic reel margin surrounding a more stratified interior lagoon. Figure 2 shows a cross-section through the reef. Pore volume and continuity vary widely. The reef margin geology exhibits high porosity and permeability and good lateral and vertical continuity. In contrast, the ref interior is characterized by varying porosity and permeability, with thin pay zones separated by thicker tight streaks. There is poor lateral and vertical community. Core studies have defined five cycles of reef growth (denoted as the R1 and R5 zone). Except in the reef margin, there is no vertical flow between these boundaries.

The "A" pool was originally developed on 64 and 160 acre) well spacing, under solution gas drive. A peripheral waterflood scheme was implemented in 1964. In 1974, a pattern waterflood scheme was implemented, as he penpheral waterflood injections were unable to support production wells in the red interior In 1975 and 1978, extensive infill drilling occurred., reducing the well spacing to 32 ha (80 acre) in many areas off the pool.
Underbalance Drilling-Surface Control Systems
Authors: Lunan B.
Published: March 2010

A closed system of surface control equipment for underbalance drilling is the safest method of controlling live wells. This new technology is particularly useful in both vertical and horizontal wells where invasion of drilling fluids into virgin formations can result in severe damage and low flow rate wells. The concept is to drill into these formations underbalanced so that there is no restriction to formation flow minimal damage and ultimately higher producing wells. This is achieved by utilizing a rotating BOP or double annular blowout preventers in combination with a choke manifold sample catcher, low stage/high stage separator, flarestack and a "live" flow through control system. The "closed system" is particularly useful in drilling in Jaw pressure and fractured reservoirs. It has been utilized to drill for oil and gas in carbonates and sandstone formations.

Introduction

During the past 18 months a significant number of oil and gas companies in Western Canada have switched from conventional drilling methods to underbalanced drilling technology when the target zone is reached. The normal operation is to drill to casing point with a conventional drilling method, set casing and cement. The heavier mud system is then changed out to a light fluid system and the well drilled ahead in an underbalanced controlled operation. The closed system on surface ensures that the well is being "controlled" during the entire drilling operation. To date over 100 wells in Western Canada have been safely drilled using this technique and it is the purpose of this paper to outline the technical results of drilling these formations underbalanced, The operational aspects are discussed in detail emphasizing the importance of the well control technique. The case studies will include a gas and an oil reservoir with example wells drilled overbalanced and underbalanced.

The Closed System

The closed system for underbalance drilling is shown in Figure 1. The principle components of the system are the wellhead connection. the rigid flowline piping, choke manifold, sample catcher, separator, flarestack and return flow line to the drilling fluid tank, rig pump and the mixing T where the nitrogen is mixed in with the liquid system and the continuation to the drilling head. Experience has shown that the surface equipment can be tied into the drilling contractors blowout preventer system using the following methods:Tie into the flowspoot on the blowout preventer (BOP) stack (Figure 1) orThe rotating blowout preventer (REOP) Figure 2.The Rotating Blow Out Preventor

The rotating blowout preventer maintains surface back pressure up to 1,500 psi to allow drilling with air. gas. water or light muds. Drilling is faster, safer and less expensive in horizontal wells. The RBOP uses a hydraulically actuated kicking element supported on large roller bearings and isolated by mechanical seals Inside a large housing. The housing has a flange for mounting to the BOP stack and a return discharge flange. Hydraulic oil is used to actuate the package elements which ride against the belly or drill pipe.
Recent Advances In Horizontal Drilling
Authors: Maurer W.C.
Published: March 2010

This paper describes recent advances in horizontal drilling technology including multibrach wells, geosteering, advanced drilling bits and motors; new short-radius tools, and small diameter drilling systems. Multibranch horizontal wells can reduce horizontal drilling costs by 20 to 30 % and the size and number of offshore platform by up to 50%.

Geosteering systems utilize logging-while-drilling tools to accurately guide horizontal wells to avoide obstacles and gas water contacts and to significantly increase horizontal well productivity. Improved PDC and TSP bits and new high-power motors have potential wells. New short-radius motor systems 12 to 30 m (40 to 100 ft) radii allow 305 to 457 m (1000 to 1,500 ft) horizontal wells to be drilled more rapidly. Advantages of short-radius wells includesidetracking wells below gas caps or troublesome shales,intersecting fractures close to vertical wellboressignificantly reducing the length of the build sectionreducing drilling time and cost andallowing pumps to be placed lower in the wells

New small diameter systems allow 92 mm (3 5/8 in) single and multibranch horizontal wells to be sidetracked from 114 mm (4 ?) casing Implementation of these new technologies should significantly increase the use of horizontal wellsworld wide.

Multibranch Wells

One of the most important developments with horizontal drilling is the increased use of multibranch wells. Figure 1 shows a Soviet (1) multibranch well with ten lateral. This well was drilled in the 1950's with nurbodrills. The laterals produced a 17-fold increase in oil production in this well.

Figure 2 shows a Soviet dual branch well drilled in the Macova field in 1968. This well cast 1.23 times more than a conventional well and produced 10.5 times more useful length in the pay zone.

By 1975, the Soviets had drilled over 30 multibranch and horizontal wells(2). They typically drilled vertical well just above the pay zone and then used turbodrills or electrodrills to drill five or six stand or horizontal branches 61 to 305 m (200 to 1,000 ft) into the pay zone. These multibranch wells cost 30 to 80% more han vertical wells, but produced up to 17 times more oil or gas.

From 1953 to 1980, the Soviets had drilled over 30 multibranch and horizontal well2. Including:57 development36 exploratory8 relief wells10 injection wells

A total 329 slant and horizontal branches were drilled in these wells with an accumulated pay-zone penetration of 175,260 m (575,000 ft.). This included 2120 sharply curved brances sidetracked from open holes (i. e. no cement plugs) with a total extension of 21,336 m (70,000 ft). Build rates up to 10 °/30 m (10 °/100 ft). Build rates up to horizontal branches were drilled with a maximum length of 640 m (2,100 ft) and a total length o 4,724 m (15,500) ft).

Petro-Huun 3 used a dual branch well to drain an entire Austin Chalk lease as shown in Figures 3 and 4.
The Nature And Control Of Geyser Phenomena In Thermal Production Risers
Authors: Edmunds N.R. , Good W.K.
Published: March 2010

Efficient application of Steam-assisted Gravity Drainage (SAGD) for bitumen or heavy oil recovery requires production of large fluid volumes, close to the boiling point of water. Flowing or gas/steam lifting such wells is an attractive alternative to rod pumping, but evidence is given that the flow can be unstable, due to the large energy release of flashing water. The instabilities are the same phenomena that drive cyclic eruptions in geothermal geysers.

A unique finite difference simulator is used to model and study the transient thermohydraulics of superheated water in an idealized wellbore. It is shown that some form of dynamic wellhead choking system is probably required for satisfactory control of a surface access SAGD well.

The advent of horizontal wells for thermal recovery and especially for SAGD has led to the need to produce very large fluid volumes from individual wells, at high temperatures. For optimum SAGD, the temperature in the production liner should be kept close to the steam point at bottomhole pressure (steam trap production control)(l), so as to maintain the steam chamber as deep as possible. Sustained fluid production rates of 300 m3/D or more(2) are anticipated from single producers; at this rate, wellbore heat losses will have a limited cooling effect. In most SAGD applications, then, produced water will flash as pressure declines on the way to the surface.

UTF Production Lifting Experience

At the AOSTRA Underground Test Facility (UTF)(3), SAGD testing is carried out using horizontal wells that are drilled from a tunnel located below the oil sand reservoir. Steam generation and production treating facilities are on the surface, and standard piping carries fluids to and from the well chambers. The wellheads and production control valves are about 20 m lower in elevation than the production liners. This arrangement takes advantage of gravity to avoid flashing in the wellbore and the tunnel facilities, but production is still subject to flash conditions in the riser, during the 185 m climb to the surface.

This was recognized during the design of the Phase A facilities, and it was hoped to exploit the resulting steam lift effect. The underground pump was de-rated and a steam sparge system was installed at the base of the riser to enable the lifting of cold fluids.

A summary of experience with this system is shown in Figure 1. This is a scatter plot showing the average riser pressure gradients for about 700 days of Phase A operation, as a function of riser bottomhole temperature. This temperature is expressed in terms of subcooling below the steam point, to account for varying pressure. Most days fall into one of three groups indicated, corresponding to the (I) no flashing, (II) slight flashing, and (III) high enthalpy (est. 15 – 30% quality) conditions.

The large gap between regions II and III represents conditions that were avoided due to extreme and persistent instability. In this region, flow consisted of geyser-like eruptions occurring at periods from one-half to several hours.
Redevelopment of the Brazeau River Nisku A And D Vertical Miscible Floods With Horizontal Wells
Authors: Lee J.I. , Jerhoff T.F.
Published: March 2010

A 400 m long horizontal well was drilled in both the Brazeau River Nisku A and D pools at a true vertical depth of 3,200 m. Both pools have been under vertical hydrocarbon miscible floods for over ten years. The purpose of these horizontal wells was to increase ultimate pool recovery by reducing well drawdown leading to improved GOR behaviour.

The location of the horizontal well in the Nisku A pool was selected based on the existing 2-D seismic data in an effort to further exploit the undeveloped portion of the reservoir. Two side track horizontal holes were drilled to search for the porous zone in the bottom of the reservoir prior to drilling the final horizontal hole approximately 2m above the base of the porous zone. In the Nisku D pool, vertical seismic profiling was conducted to locate the porous zone and to aid in the design of the length, depth and azimuth of the horizontal wellbore.

Both wells were open-hole completed. The initial oil rates were 300 - 400 m3/d, and the expected incremental reserves are approximately 300,000 m3 for the Nisku A pool and 260,000 m3 for the Nisku D pool, or 4 and 10% of their respective OOIP. Because of the relatively high initial oil rate of the horizontal wells, the high expenditures of $ 5 million for the Nisku A pool and $3.4 million for the Nisku D pool were paid out during the first year of production.

Introduction

The Brazeau River Nisku A and D pools are located approximately 150 km southwest of Edmonton, Alberta. Figure 1 shows the location of the Brazeau River Nisku A and D pools along with other producing Nisku reefs in the area. The first A pool well, 11- 31–48-12 W5M, was drilled in January 1978. The Nisku D pool was discovered in June 1978 with the drilling of well 7–33-48–12 W5M. The A and D pools are both sweet oil reservoirs containing light, volatile oil having a density of approximately 800 kg/m3. The respective solution GORs were 180 and 140 m3/m3. Average porosity ranges from 7 to 10% and the respective net pays are 80 m and 40 m. Average pool permeability of the A pool is 330 mD while the D pool is significantly lower at 50 mD. Table 1 summarizes the reservoir properties of the Nisku A and D pools. The oil properties and pressure information are described in Table 2.

The Nisku reefs are of the Upper Devonian Winterburn group at a depth of 3,200 m. The base of these reefs covers approximately one section (259 ha) in areal extent. The Nisku A pool is almost entirely dolomitized containing moldic vuggy pores. In the Nisku D pool, sparry calcite cement results in porosity and permeability reduction by complete or partial plugging of both intercrystalline and moldic vuggy pores. The reefs are extremely variable in terms of primary facies and diagenetic modifications; therefore, reservoir properties are difficult to correlate between wells.
Opportunities And Challenges Ahead
Authors: Ziff P.
Published: March 2010

Post-deregulation-A Decade of Growth

The Canadian Gas Industry is about to enter its twelfth year since deregulation which commenced on November I, 1985. The past decade has been one of rapid growth for the industry. Total Canadian production will reach 5.4 Tcf in 1996, double the 1985 level of 2.7 Tcf. This growth was almost entirely due to exports, which more than tripled from 740 Bcf in 1986 to 2,810 Bcf in 1996. This growth was facilitated first by existing spare export capacity, which was used up during the late '80s, and then by two major pipeline projects. The Iroquois project to the U.S. Northeast came partially onstream in late 1991, reaching about 575 MMcf/d in 1992, followed by the massive PGT expansion commenced incremental shipments of 900 MMcf/d to markets in Southern California and the Pacific North West.

With Canadian gas deregulation, the previously strict formulae based methodqlogies to protect future domestic demand were largely dropped. Today, we rely on price to ensure adequate supply. Canadian consumers have benefitted from this arrangement. The wholesale cost of gas supply (before transportation and distribution charges) under regulation averaged $2.76IMcf in Alberta from 1980 to 1985, and $ 1.72l Mcf since this time. The benefit for producers has been the volume growth described above. Although some critics have been concerned with the decrease in the Canadian reserve life from 20 plus years to 10, the U.S. has been running very nicely on an inventory of nine to 11 years for over two decades! The reserve life of proven reserves is simply the near term inventory. This has been reduced, but has had little disruptive effect. This inventory still is a far cry from the ‘just in time’ practices of the manufacturing sector.

Today-Lots of $$$, but Waiting for Transportation

The major pipeline expansions of the early '90s have stalled out in the mid '90s. Only modest expansions are planned for 1995 to 1998, until the Northern Border expansion begins. While 1994 production benefitted from the full year of PGT expansion, 1995 export growth slowed to 245 Bcf or 9%, and 1996 year to date (seven months) is up a scant 1.4%. As a result, increased sales by one company can be achieved only through decline of another company's production, or by competing for an increase in market share.

In the late '80s and early '90s it was generally thought that with the start-up of the Iroquois and PGT expansion and the Northern Border expansion around 1998, there would be adequate pipeline capacity from western Canada to release the excess supply that existed after the deregulation process in Canada. However, since the early to mid '90s there has been a substantial influx of capital into the Canadian oil and gas industry which has been translated into record drilling levels and another build-up of excess deliverability in the western Canadian producing region.

Even with the Northern Border expansion, now delayed by one year to the end of 1998, excess deliverability and a need for additional pipeline capacity will remain in western Canada.
Oil Re-injection to Mitigate Solvent Coning
Authors: Patel R. , Tang J. , Batycky J. , Lai F. , Okazawa T.
Published: March 2010

After solvent breakthrough, vertical miscible floods are characterized by rapid increases in producing gas-oil ratios, which in, turn are accompanied by rapid declines in oil production. At this advanced stage of depletion, the vertical floods have a low reserve life index and, hence, major investments cannot be justified to extend the producing life of these floods.

Imperial Oil Resources Limited, in its search for new low cost techniques to increase reserves while maintaining/increasing oil production, began to examine the concept of oil reinjection in its Pembina Nisku reservoirs. Exploratory laboratory tests and numerical simulation work demonstrates that a dual completion to re-inject part of the produced oil back into the formation, a few metres above the producing perforations, could lead to incremental recoveries. Simulation results specifically showed a 2 – 3% of the original-oil-in-place (OOIP) increase for the model studied.

A field test to evaluate the benefits of the oil re-injection process is presently being conducted in the Pembina Nisku "Q" pool. Initial results indicate that oil re-injection is successful in controlling solvent production while maintaining oil rates. As a consequence, additional piloting to expand the applicability of the oil re-injection process is being planned for other Nisku and Imperial Oil reservoirs.

Introduction

The Pembina Nisku area is located approximately 120 km west of the city of Edmonton, Alberta, Canada (Figure 1). The Pembina Nisku discoveries were the result of a seismic exploration play initiated by Chevron in the mid 1970's(1).

Imperial Oil operates seven vertical miscible floods in this area, These pools are relatively small in areal extent (130 ha - 325 ha) with OOIP ranging from a low of 1,700 km3 to a high of 5,000 km3. Vertical miscible floods were initiated in these pools in the 1982 to 1987 time frame.

Figures 2 and 3 show the oil production and GOR performance of the Imperial Oil operated miscible floods. Oil production from these pools peaked in 1987 at approximately 5,100 m3/day. The gas-oil ratios (GOR) remained at the base level of 150 m3/m3 through 1987 but then, as a result of solvent breakthrough, started increasing rapidly to the present level of280 m3/m3. As is the case with all vertical miscible floods, the increase in the GOR was accompanied by a rapid decline in the oil production rates. The pools presently produce approximately 1,900 m3/day, and this represents a decline of more than 60% from their peak rates.

The Nisku pools have now recovered approximately 88% of their reserves with individual pool recoveries approaching 70% of the OOIP. The low remaining reserves combined with high individual pool recoveries make it difficult to justify major capital

FIGURE 1: Nisku regional geology and pools, Pembina area, Alberta, Canada.

FIGURE 2: Imperial Oil operated Pembina Nisku miscible flood-oil rate. investments to extend the producing life of these pools.
Computers-Black Box Or Tool Box?
Authors: Mattar Louis
Published: March 2010

The, theme of this issue is "Computer Applications." Accordingly, it isbefitting to comment on the effect that this technology has had on ourpetroleum industry. As I am preparing this editorial, I reminisce about a Christmas 21 years ago, when my wife bought me a calculator (programmable) for$ 1,000! Today, its equivalent does ten times more for one tenth the price! As Robert Cringila said: "If the automobile had followed the same developmentcycle as the computer, a Rolls Royce would cost $100 today, get a million milesper gallon and explode once year, killing everyone inside." So, what has thismind-boggling silicon chip done to improve the oil and gas industry in Alberta?

Of course, today, the first thing one talks about at coffee is the Internet. Yes, both the post office and the telephone companies are on their way toextinction! There are singing Christmas cards (messages) I could have e-mailedall over the world, at no cost (and donated the savings to the food bank). But I am told, the Internet is not only transistory, it is also transitory. Itwon't be long before it is replaced by some form of Globalnet in whichtelevision, radio, telephone, computing etc., are all one amorphoustelecommunications ganglia (cellular phones will be replaced by implants inyour ear, and who knows, TV and computer screens by LCD colour retina chips). But, "with the sound of sugar plum fairies dancing in my head" am I beingcarried away by the spirit of Christmas?

Video Games

The graphics technology of video games has been implemented in computerprograms for reservoir visualization. We can integrate seismic images, petrophysical logs and geological models to build a 3-D picture of ourreservoir-slice it, dice it, rotate it, look inside and monitor the rate ofadvance of a water flood, or determine the regions of unswept oil for infilldrilling (in 64 million colours). It is very easy, and tempting to spend moretime "playing" with our computer programs than "studying the problem."Presentation has taken over from technical content-sad but true. Have computersimproved our productivity? In the areas of automation, communications androbotics, clearly yes. In many other areas, our efficiency has decreased. Onestudy shows that the average document goes through a word processor thirteentimes before it is completed! Today, we can learn more and more about less andless, and it is easy to lose sight of the forest for the trees. We can measure100,000 pressures with electronic gauges, at one-second intervals, withunprecedented accuracy, in an attempt to define our reservoir which, in fact, is being modelled as a simplistic homogeneous box-a little overkill, don't you think?

If I had a Hammer

When we have a new tool (toy) that we like, it tends to dominate our thinking. If I have a hammer, suddenly everything looks like a nail! When the concept ofdual porosity was first introduced, many reservoir models "became" dualporosity overnight.
Tips, Tricks And Traps of Material Balance Calculations
Authors: Carlson M.R.
Published: March 2010

The author has encountered a number of situations where drastically different interpretations are possible from oil material balances. The paper focusses on two of these field situations. In the first case, a gas cap could be interpreted which subsequent analysis disproved. In the second case, regression techniques converged to a total of three different combinations of gas cap and oil leg sizes. The existence of multiple solutions was not readily apparent.

The discussion is approached from three different perspectives, which are referenced to two different field examples:How production, geological, PVT (oil, gas and water) and historical information may be used to screen results and to apply the mathematical technique.A new mathematical approach to error analysis for the Havlena and Odeh material balance has been developed which the author has not seen elsewhere in the literature. Additionally, graphical interpretation can identify situations where multiple interpretations are likely.A spreadsheet has been used to implement the Havlena and Odeh material balance. Using some simple macros it is possible to quickly generate all of the diagnostic plots. This is a cost effective alternative to purchase of a specialty program. Aquifers are also included as well as statistical regression. Convergence is demonstrated as a criteria for confidence in material balance calculations.

The new interpretations were significant. In the first case, it was an important factor in deciding to proceed with a string of successful workovers designed to recover attic oil. In the second case, the new interpretation cut short a field extension drilling, program which was resulting in unexpected dry holes.

Introduction

This paper is based on half a dozen material balance studies that the author has prepared on a consulting basis. Four were for carbonate reservoirs and two were for sandstone reservoirs. The contents are based on this experience and thus represent a mixture of field case, theoretical analysis (developed during projects) and an evolving approach to material balance calculations. Two examples are given, however, they represent the combined experience on all of the above reservoirs. Scales have, for the most part, been removed; since the data is from actual studies. The paper has been structured as follows:A quick summary is made of the material balance equations. These are used for the derivation of the error analysis. No derivation of the equations was made since this is comprehensively covered in many reservoir engineering textbooks. A summary of the various Havlena and Odeh plots is also made, since this material is discussed in the paper.An analysis of the effects of errors in pressure measurement is presented. The author uses this for weighting data points.Some practical observations are made on statistical minimization.The general approach used by the author is outlined.Two typical material balance situations are described, which highlight error analysis and data screening.

The paper differs slightly from the norm for a technical paper.