Attic Oil Research Articles

Reserves growth in a mature oil field: The Devonian Leduc Formation at Innisfail field, south-central Alberta, Canada

Oil has been continuously produced from the Devonian Leduc Formation at Innisfail field since its discovery in 1957. To date, cumulative production at Innisfail is 98.9% of recoverable oil in place (84.3 MMBO) and indicates that the Leduc is near the end of its productive life. A sequence-stratigraphic interpretation produced from core, well logs, and three-dimensional (3-D) reflection seismic data, however, suggests that production may be extended through the development of two previously undetected scenarios of bypassed oil entrapment: (1) attic oil accumulations associated with small buildups atop the isolated Innisfail platform and (2) backstep-edge accumulations located in positions structurally low to currently producing wells. In both cases, oil accumulations are related to a Leduc depositional history that was characterized by rates of long-term carbonate sediment accumulation exceeded by the rate of sea level rise. Positive bathymetric relief created at the time of deposition and, subsequently, present-day stratigraphic traps were produced during the final phase of stratal retrogradation that immediately preceded the drowning of the isolated Innisfail platform. High-quality 3-D seismic data are essential in the exploration for both attic and backstep-edge oil accumulations at Innisfail. Integration of 3-D seismic data, well-log, and core data indicates that although depositional relief on both types of features may be low, they are nonetheless seismically resolvable. The small platform-top buildups are up to 0.16 km2 (40 ac) in diameter and have up to 10 m (33 ft) of independent closure above spill point. Backstep-edge oil accumulations occur within the structurally highest parts of the Leduc high-frequency sequence G downlap limit. Depositional relief along the downlap limit and associated trap closure ranges from approximately 5 to 15 m (16 to 49 ft). During 2003 and 2004, two platform-top buildups were directionally drilled, and one existing well located near a backstep-edge position and suspended since 1988 was reactivated. All three wells are successful and, to date, have cumulative production of 71 thousand bbl of oil. A total of 17 platform-top buildups and backstep-edge development drilling prospects exist across Innisfail and have expected-case recoverable reserves of approximately 960 thousand bbl of oil. These reserve additions suggest the potential for 1.14% field growth at Innisfail and are representative of the potential value that may yet exist within all mature Leduc fields in western Canada.

Ardmore Field: rebirth of the first offshore oil field, UKCS

The UK’s first offshore oil production began in June 1975 from the Argyll Field. In a 17-year period the field produced 72.6 million barrels of sweet, light crude. However, in 1992, production from the field became uneconomic, the field was abandoned, all wells were plugged and the facilities removed. In January 2002 two new oil companies, Tuscan Energy and Acorn Oil and Gas, were awarded the licence to redevelop the Argyll Field – now renamed Ardmore. A field development plan was submitted to the DTI and approval granted in October 2002. The first Ardmore well was drilled in the summer of 2003 and ‘second’ oil flowed in September 2003. Ardmore is a geologically complex field with four distinct reservoirs, of which the three oldest appear to be in both pressure and fluid communication. During the ‘Argyll’ production years (1975–1992), vuggy, karstified, Zechstein carbonates were then interpreted to have delivered about 80% of their oil in place. Rather than reflecting an error in volumetrics (underestimated STOIIP) the oil is interpreted to have come from the underlying Rotliegend and Devonian sandstone reservoirs. Natural aquifer support was significant for the Rotliegend, and probably the Zechstein reservoirs, while the volumetrically dominant Devonian reservoir produced via pressure depletion. Recovery from Jurassic sandstones on the west flank of Ardmore was minimal. Vertical and low deviation subsea wells tied back to a floating production system were used for the initial development of Argyll. As production progressed, the increasing water cut and lower reservoir pressure required artificial lift for most wells. The limited amount of gas available restricted the number of wells which could be produced. There were several wells drilled late in field life which tested oil using nitrogen gas lift but which were abandoned without being produced due to the restrictions of the gas lift system. Argyll was abandoned in 1992 with an average water cut of about 70%. Detailed subsurface studies, integrating the geology, geophysics and petrophysics with the 17 years of dynamic data, have led to a better understanding of the field performance and have allowed new development targets to be identified. The redevelopment of the field targets a combination of attic oil in Zechstein, bypassed oil in the Rotliegend, resegregated oil in the Zechstein and Rotliegend and unproduced but proven oil in the Devonian.

Seismic reprocessing contributes to development success at the Elang Field, Northern Bonaparte Basin

The 3D data set over the Elang Field, Northern Bonaparte Basin, was reprocessed to provide greater confidence in mapping the structural configuration of the field and to investigate infield development opportunities. The original (1994) data set, which was acquired and processed in the inline (strike) direction, suffered from poor resolution and reflection coherency and multiple contamination at the reservoir level.The reprocessing strategy included rebinning and HVA analysis in the dip direction followed by radon demultiple applied close to the HVA velocities. The result was a significant improvement in resolution of reservoir horizons and faults. Interpretation of the reprocessed data yielded a simpler structural picture of the Elang Field with the crestal area interpreted as a simple rollover with little or no erosion of the reservoir section. The interpretation also confirmed significant attic oil potential in vicinity of Elang-1. This potential was tested in January 2000 by Elang-1/STl which intersected the reservoir 28 m up dip of Elang-1 and close to the prognosed depth. Production from the well has exceeded pre-drill predictions and added substantial incremental reserves to the field. This has increased value to the project and extended the life of the Elang production facility.

Modeling combined fluid and stress change effects in the seismic response of a producing hydrocarbon reservoir

Editor's note: A fuller version of this article can be downloaded in pdf format from the GUMPA project Web site at the following URL - http://www.pet.hw.ac.uk/research/gumpa/index.html The exploration and production of hydrocarbons are generally accomplished with the aid of 3-D seismic to image reservoir structure and, in some instances, reservoir properties and direct hydrocarbon indicators. Repeated seismic surveys over a period are termed time-lapse seismic (and sometimes 4-D seismic ). Changes observed in the seismic character with time have been attributed to impedance changes as a result of production (e.g. Gawith and Gutteridge, 1996). These changes have been used in a few producing fields to monitor reservoir performance. Identifying observed differences in repeat 3-D surveys and relating these to either in-situ saturation or stress-state changes, or both, has been difficult because of the lack of control data. It has been noted that in some fields (Watts et al., 1995), the sensitivity to stress changes can be very much greater than the sensitivity to saturation changes. In other fields (Landro et al., 1999), the saturation changes are thought to be more significant. To aid understanding, a need for greater integration of geophysics and reservoir engineering has been noted and was the motivation for this study (Jack, 2001). There is a limited window of opportunity in a field's producing life when there are sufficient changes (saturation or stress) in the subsurface to show a surface seismic response. These changes have to be monitored before the field has reached significant decline for the observed changes to be exploited for reservoir management (through in-fill drilling for by-passed, compartmentalized or attic oil). Reservoir modeling is an essential tool for managing the development of and production from hydrocarbon reservoirs. Many technical issues however surround the realism and validity of the models on which management decisions are based. …

Seismic Reprocessing Contributes to Development Success at the Elang Field, Northern Bonaparte Basin

The 3D data set over the Elang Field, Northern Bonaparte Basin, was reprocessed to provide greater confidence in mapping the structural configuration of the field and to investigate infield development opportunities. The original (1994) data set, which was acquired and processed in the inline (strike) direction, suffered from poor resolution and reflection coherency and multiple contamination at the reservoir level.The reprocessing strategy included rebinning and horizon velocity analysis (HVA) in the dip direction followed by radon demultiple applied close to the HVA velocities. The result was a significant improvement in resolution of reservoir horizons and faults. Interpretation of the reprocessed data yielded a simpler structural picture of the Elang Field with the crestal area interpreted as a simple rollover with little or no erosion of the reservoir section. The fault interpretation, aided by edge detection and coherency cube results, differs from the original 3D interpretation and is now characterized by a simple east-west fault pattern at the reservoir level.Reservoir mapping confirmed significant attic oil potential in the vicinity of Elang-1. This potential was tested in January 2000 by Elang-1/ST1 which intersected the reservoir 28 m up dip of Elang-1 and close to the prognosed depth. Production from the well has exceeded pre-drill predictions and added substantial incremental reserves to the field. This has increased value to the project and extended the life of the Elang production facility.

Screening Criteria to Evaluate the Development Potential of Remaining Oil in Mature Fields

Summary Continuing reservoir management at mature stages often concentrates on delineating pockets of remaining mobile oil. This is becoming a major task for reservoir geologists and petrophysicists. Many old fields are coming up for reactivation as investment opportunities and there is an overall expectation that modern techniques can lead to additional recovery of between 10 and 20%. In this article we will discuss the screening criteria related to reservoir architecture, accumulation condition and production history. The mobile oil remaining can be found in a number of predictable locations in reservoirs depending on their structural style and facies. Attic oil along faults is perhaps the most simple configuration but sizeable volumes of remaining oil can also occur as a function of reservoir stratification and lateral discontinuity. A systematic overview of the different play types has been compiled based on structural or stratigraphic lateral continuity and vertical reservoir connectivity. Screening criteria have been derived on the basis of field examples and models for four play types. The screening criteria specify minimum conditions which may lead to economic re-development with horizontal sidetracks from existing wells. In addition recommendations are given with respect to data gathering to confirm the presence of economically viable targets.

Horizontal Well Technology-A Key to Improving Reserves

Abstract In recent years, horizontal wells have been very successful in increasing productivity, adding reserves, and improving the overall cost effectiveness of field operations. As a result, many operators are including the utilization of horizontal wells as an important element in their reservoir management strategy. Horizontal wells are being used in a variety of conditions: intersecting natural fractures, reducing water and gas coning, exploiting thin oil and gas zones, enhancing heavy oil recovery, tapping unswept oil, improving sweep, producing attic oil, and connecting discontinuous zones. Limited success has also been observed for thermal and low-permeability applications. In spite of documented successes in these areas, several challenges still face this technology. They include:sufficient pre-work including reservoir characterization during the candidate selection process,effectively integrating horizontal wells in over all reservoir management strategies,sufficient post-appraisal of performance versus a plan in trying to learn more about the successes and failures with horizontal wells, andthe perception that horizontal wells are only applicable in selected cases and not desirable if vertical wells are already performing well. The presentation focusses on three items:an evaluation of horizontal drilling and completion potential of various prospects,a discussion of some advances in horizontal well technology, anda review of case studies summarizing key aspects and emphasizing the use and misuse of this technology. Introduction Horizontal well technology is receiving notable attention for increasing productivity, adding reserves, and improving the overall cost-effectiveness of field operations. As a result, many companies' vision involves greater utilization of horizontal wells for enhancing their profitability (see Figure 1). Provided the pre-work has been performed during the candidate selection process, horizontal wells can be used in a wide range of applications. Figures 2, 3 [Reference (1)], and 4 provide several situations where horizontal wells have been successful economically, including intersecting natural fractures, reducing water and gas coning, exploiting thin oil and gas zones, enhancing heavy oil recovery, tapping unswept oil, improving sweep, producing attic oil, and connecting discontinuous zones. Limited success has also been observed for thermal and low-permeability applications. In spite of the above documented successes, several challenges still face this technology:sufficient pre-work including reservoir characterization during the candidate selection process,effectively integrating horizontal wells in the overall reservoir management strategies,sufficient post-appraisal of performance vs. a plan in trying to learn more about their successes and failures with horizontal wells, andthe perception that horizontal wells are only applicable in selected cases and not desirable if vertical wells are already performing well. It is not correct to say that horizontal wells can be a saviour where vertical wells have proven unsuccessful. However, one should note that a majority of "good horizontal wells" were in reservoirs where the vertical wells were good. As a general rule, readers are encouraged to consider horizontal wells as the primary option for a field, unless otherwise applicable.

Tips, Tricks And Traps of Material Balance Calculations

Abstract 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.

Concepts And Opportunities In Using Horizontal Wells In High Quality Reservoirs

Abstract A considerable fraction of Alberta's, and the world's, oil has been produced from high quality reservoirs dominated by gravity drainage. However, almost all of these reservoirs in North America have been completely flooded with gas, solvent or water, and are nearing economic limits with vertical wells. Often reservoir simulations show little economic incentive to drill horizontal wells for incremental recovery of sandwich or attic oil, because very high permeability minimizes cone heights. Nevertheless, many of Husky's horizontal wells, which have been produced from these types of reservoirs, have been extremely successful(1). Heterogeneity The most obvious reason for an unexpected success in high quality reservoirs is the effect of higher than anticipated heterogeneity on oil drainage. Even though average permeability at a well may be in the darcy range, the consequence of low permeability layers on the cone shape C3n be extreme (Figure 1). The existence and effect of these low permeability sheets is often a surprise, because log, core and production data alone do not provide one with the full story of heterogeneity and fluid flow in the reservoir. Estimating the lateral extent of tight zones shown on logs is difficult when interwell spacing is less than the extent of these tight zones. Also, many thin low permeability layers are not clearly identified by most logging tools. Stylolites, and other very thin impermeable zones, are often avoided in selection of core for analysis, but can extend far enough laterally to seriously restrict vertical fluid flow(2). A simulation history match of production data can be accomplished using a high residual oil saturation, instead of a representation of bypassed oil zones caused by reservoir heterogeneity. Therefore, a very careful analysis of log, core and production data is required to identify heterogeneities. Other methods which can help one determine the location and extent of permeability "barriers" are pressure interference testing, interwell tracing, gathering fluid type and saturation data from infill wells and testing intervals of existing wells. Lateral heterogeneity can also play a major role in oil drainage. For example, porosity stringers at the margin of a reservoir are often poorly drained (Figure 1). The location of these stringers can sometimes be determined with more advanced seismic techniques. Mechanics of Interval Isolation Another reason for horizontal well success is simply the challenge of producing from a thin oil interval with a vertical well. Formation damage, poor cement, and equipment malfunctions all contribute to hinder vertical well production (Figure 2). Recent technological advances have reduced the severity of these problems in some newly drilled and completed wells, however, many high quality reservoirs are being produced through older wells. Low Drawdown, Wellbore Crossflow and Fluid Separation Horizontal, and in some cases vertical, wells can produce at economic rates from very high penneability zones at almost no drawdown. Producing 100 m3/d of light oil from a 1,000 m long horizontal well in a massive reservoir with 2 darcies permeability will result in a drawdown of only 3 kPa3.

A WAG injection pilot in the Lower Brent Formation at the Gullfaks Field

Abstract The Gullfaks Field is a large oilfield in the Norwegian Sector of the North Sea. The field is compartmentalized by a dense and complex fault pattern, and most of the oil is contained in poorly consolidated but high-quality reservoir sands. Production started in 1986, and waterflooding is the main recovery method. Water-alternating-gas (WAG) injection — or supplementary injection of gas in existing water injection wells — has been identified as a possible method for increasing and accelerating oil recovery from Gullfaks. To verify the potential of this technique, a WAG pilot was initiated in 1991. The target area for the gas was primarily one fault block where major water breakthrough had occurred. In this paper, relevant field observations are presented, and the effects of the WAG pilot injection on flow performance and recoveries are discussed on the basis of the field observations and a detailed, history-matched 3D simulation model for the pilot area. In the present case, the gas migrates rapidly towards the top of the formation and accumulates in secondary gas caps. Improved immiscible displacement of attic oil is the main benefit of gas injection in this case.

Evaluation of Attic Oil Recovery Schemes For the Fenn West Leduc D-3E Reef Reservoir

Abstract Reservoir simulation was employed to evaluate various attics oil recovery schemes for the Fenn West Leduc D-3E reef reservoir. Based on geological and seismic data, a three-dimensional reservoir model was constructed to represent the pinnacle-reef reservoir and the adjoining bottom aquifer. The reservoir model was calibrated by history matching the production performance of the two vertical wells in the pool. Model calibration results indicated that water production from the pool is mainly attributable to a rising oil-water contact in the reservoir. Furthermore, the current oil production from the pool results from a reverse oil coning mechanism in the attic portion of the reef. Various attic oil production schemes were investigated, including increased liquid withdrawals, reactivation of a shut-in vertical well and horizontal well production from the structurally highest location in the pool. Prediction results indicated that these attic oil production schemes will not recover any significant incremental oil reserves from the pool, but will shorten the remaining producing life of the pool by five to 21 years. Introduction The Fenn West Leduc D-3E pool, located in Township 36, Range 21, West of the Fourth Meridian (Figure 1), is a pinnacle reef reservoir containing light gravity oil (34 °API). Discovery well 08-11-36-21 W4M commenced production from the pool in January 1983, at an initial oil rate of over 300 m3/d (Figure 2). After producing clean oil for over four years, a series of well recompletions was conducted to arrest the increasing water production from the well (Figure 2). In September 1991, the well was suspended due to a high watercut of about 98%. Another well, located at 07-11-36-21 W4M, commenced production in December 1985. The well produced clean oil for over three years and is currently producing at an oil rate of about 12 m3/d and a watercut of about 86% (Figure 3). A third well, located at 09-11-36-21 W4M, previously produced from the Nisku Formation and was converted to a water disposal well in 1987 (Figure 1). Based on pool pressure and production data, the main recovery mechanism in the pool is an active bottom water drive. To April 1992, about 483,500 m3 of oil, 262,900 m3 of water and 38,600,000 m3 of gas have been produced from the pool. Based on data from the Energy Resources Conservation Board (ERCB)(1), the volumetric estimate of original oil-in-place (OOIP) for the pool is about 1,480,000 m3. Correspondingly, the current oil recovery is about 33% of the OOIP. The objective of this study was to evaluate various attic oil recovery schemes for the pool including increased pumping rate for well 07–11, reactivation of well 08–11 and horizontal well production from the structurally highest location in the reservoir. FIGURE 1: Pool location map: Fenn West Leduc. D-3E pool. (Available in full paper) Geology The Fenn West Leduc D-3E pool is extensively dolomitized, resulting in a very high quality reservoir. The average porosity is about 6% and the average horizontal permeability is in the order of several Darcies.

Multiple Contact Phase Behaviour In The Displacement Of Crude Oil With Nitrogen And Enriched Nitrogen

Abstract Phase behavior tests were carried out on a Nisku crude oil (a candidate reservoir for nitrogen flooding) with nitrogen and nitrogen mixed with carbon dioxide or propane. These measurements were carried out in a batch wise multiple contact mode to simulate what occurs when gas displaces oil in a porous medium. None of the mixtures achieved miscibility with the oil in four contacts at pressures up to 35 MPa. Nitrogen and methane were exchanged between the gas and oil phases in an almost 1:1 ratio, while gas enrichment with C2–5 hydrocarbons proceeded at a much slower pace. The experimental data were matched using the Peng-Robinson equation of stale. Good agreement between experimental and calculated results was obtained in most cases. This applies to the equilibrium phase compositions, as well as to the liquid phase densities and gas/oil ratios. The largest deviations were in the amount of heavy ends found in the vapour phase. Introduction Nitrogen may be applied for enhanced oil recovery (EOR) in several modes, e.g. pressure maintenance, cycling condensate reservoirs, attic oil production, producing gas-cap gas, chase gas for hydrocarbon or carbon dioxide slugs and miscible displacement of oil. These applications were discussed by Clancy et al.(1) and reviewed in detail by Sayegh et al.(2). Recently Leonard(3) summarized EOR activity worldwide. From this article it was noted that there are seven nitrogen injection projects in the U.S.A., four of which have already showed profit, while it is too early to tell the remaining three. In addition, there are three flue gas injection projects. In Canada, two ongoing floods utilize nitrogen. The first is in a Pembina Nisku reef, wherein the injection gas consists of a mixture rich in nitrogen along with carbon dioxide and light hydrocarbons. The second is the Willisden Green flood, where nitrogen is being used as a chase gas for a hydrocarbon slug. The advantages of using nitrogen for EOR include: widespread availability from air liquefaction, non-toxicity, non-flammability and non-corrosivity. In addition, the price of nitrogen appears to be competitive with that of dry hydrocarbons, although it is difficult to give more precise estimates because of the many variables involved in costing. Wilson(4) noted that nitrogen has some disadvantages in its use for enhanced oil recovery, which include:The cost of separating nitrogen from the produced hydrocarbon gases. This is offset if the produced gases are recycled into the reservoir.Nitrogen asphyxia.If air separation units are used to produce nitrogen, then a by-product stream rich in oxygen is produced. This stream has to be well separated from any hydrocarbon streams in the vicinity. In summary, the use of nitrogen in enhanced oil recovery has many advantages that can outweigh its disadvantages. This is a new topic, and there are many gaps in the information available for its proper application. It is the purpose of this work to try and fill in some of these gaps.

Gas Injection for Upstructure Oil Drainage

Any attic oil project tries to displace with gas the oil located above the structurally highest well in the reservoir. Results from a numerical simulator show that the most important controllable variable in attic oil recovery is the volume of gas injected during each cycle. A method is presented for calculating the required gas injection volume for each cycle presented for calculating the required gas injection volume for each cycle of an attic oil project. Introduction Oil recovery from high-relief reservoirs can be increased by downstructure gas injection. In this process, often called "attic oil recovery," gas is injected in the structurally highest well in the reservoir. The injected gas will migrate upstructure, forming a secondary gas cap and displacing oil downward.In high-relief reservoirs, which typically occur around "piercement type" salt domes, field development is complicated by the lack of control on the upper limits of the structure. To ensure a commercial completion, operators usually locate development wells a safe distance from the estimated sand/salt interface. In reservoirs with an active bottomwater drive, much of the updip oil will not have been produced when the highest well in the structure waters out. Sidetracking or drilling new wells is expensive and risky. It would be almost impossible to locate new wells to drain all updip oil adequately. Reservoirs with steep dip and high permeability allow injected gas to migrate to the most permeability allow injected gas to migrate to the most inaccessible areas of the pinchout, providing good lateral coverage. Injected gas may be traded economically for oil as long as the price of a unit volume of reservoir oil is sufficiently greater than the price of a corresponding unit volume of reservoir gas.Many authors have reported on field applications of the attic oil recovery process. In 1971, Combs and Knezek published theoretical guidelines and field data concerning the maximum gas/oil segregation rate and the minimum and actual gas requirements to recover 1 bbl oil.This paper presents results of a numerical model study of an attic oil recovery process and defines the variables that control the reservoir performance of a successful project. A method is presented to calculate the required project. A method is presented to calculate the required gas injection volumes. Numerical Model The numerical model used in this study is a conventional beta model that was modified to simulate the attic oil recovery process properly. The model includes these features: three-phase flow of oil, water, and gas; gas/oil solubility; gas/oil and oil/water capillary pressure; three-phase relative permeability with hysteresis effects; variable bubble-point scheme; variable flow rates; gravity effects, both areally and vertically; conformance to any reservoir geometry; and variable rock and fluid properties. properties. Even with the advent of relatively efficient three-dimensional reservoir simulators, computing costs for a meaningful study can become expensive. A two-dimensional areal model can simulate the same problem, provided the distribution and flow of fluids in the vertical dimension is included implicitly in the areal model. Several authors' have reported on the theory and calculation techniques of "pseudofunctions." Jacks et al. presented a technique for calculating the "dynamic pseudofunctions" that could be applied over a wide range of How rates and initial fluid saturations. JPT P. 1323

An Engineering Challenge Development of South Louisiana's Giant Timbalier Bay Field

LIPARI, C.A., JUNIOR MEMBER AIME, GULF OIL CORP., MORGAN CITY, LA. Abstract The Timbalier Bay field, covering 9,500 productive acres of inshore and offshore area, containing 81 productive horizons and some 434 reservoirs ranging in depth from 2,000 to 17,500 ft, presents a challenge to engineers. Reservoir mechanisms of many combinations make it necessary that water flooding, gas injection, attic oil recovery and other recovery methods be examined for possible application in this filed. This paper presents the history and characteristics of the field and the approaches taken by Gulf Oil Corp. in arriving at a system of operation in the coastal waters of South Louisiana. Introduction The operation of an oil field in the coastal area of Louisiana is similar in many ways to operations elsewhere, but there is one significant difference. The operation takes place over a body of water. The logistics of an operation of this type require that all functions be coordinated carefully if the project is to be successful. Throughout 24 years of operating the Timbalier Bay field, Gulf Oil Corp. has employed more efficient equipment as it became available, and the most efficient operating practices known at the time. The purpose of this paper is to convey to the industry the history and the practices followed by Gulf Oil in developing this field in the coastal waters of South Louisiana. Location and General Description The Timbalier Bay oil and gas field is located in, and offshore from, Lafourche Parish, La. (Fig. 1). It is situated approximately 20 miles south of the town of Golden Meadow, 70 miles southeast of Morgan City (the area operational office) and 60 miles southwest of the city of New Orleans. The crest of the structure lies almost directly underneath East Timbalier Island. This low-lying island, averaging about 350-yd wide, is the site of the central Timbalier Bay field camp (Fig. 2) and separates the open waters of the Gulf of Mexico from the shallow Timbalier Bay waters. Access to the field is from the Leeville shore base, through Bayou Lafourche, into Timbalier Bay and the Gulf of Mexico, Presently, there are 410 completion intervals in 277 wells. Daily production is 33,826 STB of oil and 52 MMcf of gas. The productive portion of the field covers approximately 9,500 acres, The present lease arrangement (Fig. 3), within the present productive area of the field, consists of Gulf Oil Corp. as sole owner and operator of Louisiana State Lease "PP" 192, 1772 and 1773, and operator for the joint interest of the Louisiana State Leases 1423, 1483 and the Outer Continental Shelf Lease 0263, Block 21. Union Oil of California operates Louisiana State Leases 3088 and 3324, and Tenneco operates Louisiana State Lease 1369.Surrounding fields are (Fig. 1) Bay Marchand to the cast, Caillou Island to the west, Lake Raccourci to the north and South Timbalier Area Block 54 to the south. JPT P. 127^

Cellar Oil

Introduction Small, steeply inclined reservoirs without natural water drives often are found associated with salt domes or other highly faulted structures. Frequently, only one well may be economically justified in these reservoirs, from which oil is produced by an expanding gas-cap drive or by a dissolved-gas drive. Although a large fraction of the oil upstructure from the well may be recovered during primary depletion, only a small fraction of the downdip oil can be produced because of gravity effects. This downdip oil has been defined as "cellar oil"' in contradistinction to "attic oil" which is the oil above the structurally highest well in reservoirs where a natural water drive is present. In this study, two methods of producing cellar oil by water flooding a one-well reservoir were investigated by means of a laboratory model. This model was scaled to represent a prototype reservoir having an area of 30 acres, a permeability of 500 md, and a thickness and dip of 30 ft and 30, respectively. One method considered, the simultaneous injection of water and production of oil from a single well, would require that the lower portion of the productive interval of a well be completed for water injection and the upper portion for oil production. The other method considered, intermittent injection, would involve alternate injection of water into and production of oil from a single well. Injection of water into the formation would repressure the reservoir, causing gas to go back into solution. Since some of the injected water would flow updip from the well, water injection usually would be followed by a waiting period during which the water could drain from above the wellbore. Production of oil by gravity drainage and gas-cap drive could be initiated when water drainage became sufficiently complete. The amount of water produced along with the oil would naturally depend on how soon after water injection ceased that production was started. This process could be repeated in cycles until oil could no longer be produced economically. Of these two methods, the intermittent injection technique would be simpler to put into operation since it does not require a dual completion. Also, it is probably more generally applicable than the simultaneous injection-production method. It is to be expected that in some reservoirs the rock and fluid properties would be such that practical oil-production rates could not be achieved by the simultaneous technique. However, in reservoirs where the simultaneous method will result in practical rates of oil production, it does have the advantage of permitting immediate, continuous oil production; whereas in the intermittent method, oil production is interrupted by periods of water injection and drainage. It was the objective of this study to determine whether these two methods of cellar oil production are practical for the representative prototype investigated and to evaluate their relative merits.