A new method for simultaneously determining the permeability and porosity of low-permeability cores is described.This method uses unsteady-state gas t1ow, which results in rapid tests. Equations are presented that describe the pressure response as a function of porosity and permeability. Comparisons of results to numerical simulations and conventional core-analysis methods are presented that verify the method's accuracy.

The results described demonstrate the conditions which the gas and oil relative permeabilities are independent of the connote (initial) water saturation. Summary Gas and oil relative permeabilities were measured on water-wet and mixed-wet Berea sandstone at various connate (initial) water saturation values, including zero, using the gas flood method. The centrifuge method was used to extend the measured oil relative permeability curves to lower total liquid saturations than could be permeability curves to lower total liquid saturations than could be achieved by gas flood. Composite cores were used in the gasfloods, whereas individual plugs were tested in the centrifuge. The results show that gas and oil relative permeabilities are independent of the connate water saturation in water-wet and mixed-wet Berea sandstone provided certain conditions are satisfied. Introduction Core preparations for flow tests can be difficult and time consuming. In fact, the preparation often requires more time than the actual now measurements. Among the different preparation considerations, achieving a specific value of initial water saturation in a core is especially difficult. The objective of this study is to quantify the effect that connate water saturation has on gas-oil relative permeabilities for both water-wet and mixed-wet Berea rock. A brief qualitative discussion of the effect that water saturation has on gas-oil relative Permeability measurements was presented by Owens et al. in 1956 . Permeability measurements was presented by Owens et al. in 1956 . Although no data were shown, the authors stated that the presence of water saturation has no effect if the water is immobile. In 1965, Knopp published his results of gasflood tests performed on extracted cores without connate water and with restored water saturations." He observed no effect on the gas-oil relative permeability ratio due to the presence of the water phase. In permeability ratio due to the presence of the water phase. In 1987, Delclaud et al. presented the results of a comparison on a single core sample. No difference in production was observed between the gasflood with low water saturation and the gasflood performed with no water saturation. performed with no water saturation. In this paper, we use the term "water wet" to describe the wettability condition of Berea sandstone as received from the quarry We visualize the water-wet state as one in which a continuous film of water is always present on the rock surface; this film prevents direct contact of the oil with the surface. We use the term "mixed wet" to describe the wettability state visualized by Salathiel, in which the smaller pores are water wet and the larger pores are oil wet. Water cannot come into direct contact with the rock surface in these larger oil-wet pores. Salathiel postulated that the oil-wet pores are connected over an appreciable distance, so that oil can continue to flow at low saturations. Procedures The porous rock used in this study was Berea sandstone. A number of 2- and 2.5-inch-long (5.08- and 6.35m) plugs were cut from a three-foot (0.9-m) length of Berea stock that was 1.5 inches (3.81 cm) in diameter. Test plugs were randomly selected from those obtained from a given three-foot length of stock. Several three-foot lengths were used during this work. Table 1 gives the routine porosity and permeability of the individual plugs. Relative permeabilities were measured by two methods: gasflood and centrifuge. In the gasflood (unsteady-state) method, injected gas displaced oil from the core. The production and differential pressure data were analyzed using the Johnson-Bossler-Naumann (JBN) pressure data were analyzed using the Johnson-Bossler-Naumann (JBN) method to obtain gas and oil relative permeabilities. In the centrifuge method, the core was enclosed in a sleeve and centrifuged in air at constant speed. The volume of oil produced was recorded versus time. The production data were analyzed using a method similar to the technique described by Hagoort to obtain oil relative permeabilities. Gas relative permeability cannot be calculated from centrifuge data because the analysis assumes that no pressure gradient exists in the gas phase.

Thw paper was prepared for presentatmn al tfw Western Regional Meeting held m Anchorage, Alaska, 22-24 May 199S This paper was selec!ed lor presentahon by the SPE Prcgram Comm!tlee folfowmg revmw' of Informalton cnntamed In an abstracf submmed by the author(s) Contenls of the paper as presented, nave nO[ been rewewed by the Soctety of Petroleum Engnwers and are subjecf to correcton by the authcr(s) The maternal, as presented, does not necassanly reflecf any POSIIIO"of the Society of Petroleum Engtneers or idsm-mbersPapers presented a[ SPE meetlcgs are subject 10 publlcatum rewew by Edional Comm!ttee of the SomBly of Petroleum Engineers Permwsmn to COPY!s restricted to an abstract of not more than 3C0 works Illustrations may not be coped The abstract should contain conspicuous acknowledQmam of where and by whom the IXILI.X was presemed WWo L\brarvan, SPE, P O 833836 Rlchardso", TX 75083-3836 USA, fax 01 -214-952:!+435 ABSTRACT Production of fluids from the shallow, thick, and low-strength Diatomite reservoir in the South Belridge field has resulted in reservoir compaction, surface subsidence, and numerous well failures. The most severe subsidence problems occurred while the field was under primary recovery, prior to implementation of waterfloods for pressure support, Consequently, a significant number of wells in the field have incurred casing damage, which proportionate y limits the utility of these wellbores for cent inued production and routine wellwork operations. The nature of casing damage varies significantly depending on the location in the field, however casing shear ("kinks") generally produces the most severe problems in retaining full wellbore utility since it Iim its tool passage (e.g., packers, scrapers, etc.) and is not economically repairable using conventional milling tools. Since the mid 1980s, surveillance activities have been in place to monitor and assess the magnitude and progression of surface subsidence, reservoir compaction, and wellbore damage in Section 19 of the South Beh-idge field. Surveillance activities include the use of ground elevation markers and a variety of production logs --several of which involve novel application and log interpretation. These data subsequently were used to develop and verify hybrid geomechanics and wellbore geometric models for assessing casing damage, identifying well operability and wellbore utility limits, and forecasting remaining wellbore life from which a reservoir management plan and wellbore management operational strategies were established. A key ingredient in the implementation of this plan and operational strategies involved a cooperative tool development with a major oil tool service company to repair casing "kinked" wellbores, as an alternative to re-drilling wells. This paper provides a case history describing the various synergistic reservoir and wellbore management activities designed to effectively mitigate subsidence-induced operational problems and the accompanying field benefits resulting from their implementation. INTRODUCTION The Sou...

This paper describes a methodology for incorporating uncertainties in theoptimization of well count for the deepwater Agbami Field development. The lackof substantial reservoir description data is common in many deepwaterdiscoveries. Therefore, the development plan must be optimized and proven to berobust for a wide range of uncertainties. In the Agbami project, the design ofexperiments or experimental design (ED) technique was incorporated to optimizethe well count across a wide range of subsurface uncertainties. The lack of substantial reservoir description data is common for manydeepwater discoveries. In the Agbami project, the uncertainty in oil in placewas significant (greater than a factor of two). This uncertainty was capturedin a range of earth (geologic) models. Additional uncertainty variables, including permeability, fault seals, and injection conformance, were studiedconcurrently. Multiple well count development plans (high, mid, and low) weredeveloped and used as a variable in ED. The ED technique allowed multiple wellcounts to be quickly tested against multiple geologic models. With the netpresent value (NPV) calculated for each case, not only was the well count forthe overall highest NPV determined, but discrete testing of each geologic modeldetermined the optimum well count for each model. The process allowed testingthe robustness of any well count versus any uncertainty (or set ofuncertainties). A method was demonstrated quantifying the difference between perfect andimperfect knowledge of the reservoir description (geologic model) as itpertains to well locations. Introduction The Agbami structure is a northwest/southeast trending four-way closureanticline, and is located on the Niger delta front approximately 65 milesoff-shore Nigeria in the Gulf of Guinea (see map in Fig. 1). Thestructure spans an area of 45,000 acres at spill point and is located in 4800ft of water. The Agbami No. 1 discovery well was drilled in late 1998. Theappraisal program was completed in 2001 and included five wells and onesidetrack drilled on the structure with each encountering oil pay. These fivewells and a sidetrack penetrated an average of approximately 350 ft of oil. In this phase (Phase 3) of the development process, the key objectives areto construct a field development plan and to obtain sanctioning. With drillingdepths of up to 10,000 ft below mudline in 4800 ft of water, well costs atAgbami will be at the high end of typical deepwater costs. Therefore, animportant optimization parameter in the field development is the total wellcount. Agbami is typical of many deepwater developments in that the seismic is lessthan perfect and the appraisal well data are sparse relative to the areacoverage. Therefore, subsurface uncertainty is high. In fact, the 5% probableoil in place is more than two times the oil in place at the 95% probability. Asa result, the development process is challenged with determining the optimumwell count for the field development across the wide range of subsurfaceuncertainty. Several key development decisions were determined in the previous phase(Phase 2) of the development process. These decisions were taken as givens inthis study and are listed as follows:Recommended pressure maintenance scheme and gas disposition strategy for the17 million-year (MY) units is a combination of crestal gas injection withperipheral water injection.Recommended pressure maintenance scheme and gas disposition strategy for the14MY/16MY units are crestal gas injection only.Facility design capacity recommendations are:250,000 stock-tank bbl per day (STB/D) oil450,000 thousand cubic ft per day (Mcf/D) gas production250,000 STB/D water production450,000 STB/D liquid production450,000 STB/D water injection

Summary Production of fluids from the shallow, thick, and low-strength Diatomite reservoir in the South Belridge Field has resulted in reservoir compaction, surface subsidence, and numerous well failures. The most severe subsidence problems occurred while the field was under primary recovery, prior to implementation of waterfloods for pressure support. Consequently, a significant number of wells in the field have incurred casing damage, which proportionately limits the utility of these wellbores for continued production and routine wellwork operations. The nature of casing damage varies significantly depending on the location in the field, however casing shear ("kinks") generally produces the most severe problems in retaining full wellbore utility since it limits tool passage (e.g., packers, scrapers, etc.) and is not economical to repair using conventional milling tools. Since the mid-1980s, surveillance has been in place to monitor and assess the magnitude and progression of surface subsidence, reservoir compaction, and wellbore damage in Exxon's operations of Section 19 in the South Belridge Field. The surveillance includes the use of ground elevation markers and a variety of production logs—several of which involve novel application and log interpretation. These data subsequently were used to develop and verify hybrid geomechanics and wellbore geometric models for assessing casing damage, identifying well operability and wellbore utility limits, and forecasting the remaining wellbore life from which a reservoir management plan and wellbore management operational strategies were established. A key ingredient in the implementation of this plan and operational strategies involved a cooperative tool development with a major oil tool service company to repair casing kinked wellbores as an alternative to re-drilling wells. In this article we provide a case history that describes the various synergistic reservoir and wellbore management activities designed to effectively mitigate subsidence-induced operational problems and the accompanying field benefits resulting from their implementation. Introduction The South Belridge Field is located in Kern County, California, in the San Joaquin Valley. The field is about 45 miles northwest of Bakersfield, California. Exxon operations are located in Section 19 which is nearly in the center of the productive portion of the Diatomite reservoir. Of the 504 acres operated by Exxon (three quarters of Section 19), the productive Diatomite comprises approximately 150 acres. Reservoir Geology. The Diatomite reservoir is a biogenic siliceous deposit, with a top of reservoir at approximately 1200 ft. The productive interval can be as great as 1800 ft, with the upper 800 ft referred to as the Opal A and the lower 1000 ft referred to as the Opal CT. The Opal CT is distinguishable by a higher degree of diagenesis. The average total porosity for the Opal A is about 58% and for the Opal CT is about 42%. The estimated average liquid permeability for the Opals A and CT is 0.2 and 0.1 md, respectively. The oil gravity is about 29°API. The Diatomite zones are overlaid with productive Tulare sands. The heavy-oil producing Tulare interval consists of unconsolidated sand with minor shale layers and is up to 1200 ft thick. The main Tulare shales are about 3 ft thick and are located approximately 700 and 900 ft deep. Production Operations. The Exxon property in Section 19 is developed on a 5/8 acre spacing using a line-drive waterflood. The wells are hydraulically fractured in multiple stages and produced from both Opals A and CT simultaneously. Current oil production is about 2700 BOPD from 130 producers, making use of 130 injectors for waterflood support. The current field baseline annual decline is about 6.5%. About 50 additional off-pattern wells currently remain idle. The active wells are located in the center of the trend; the remaining drill sites are available towards the east and west fringes of the productive area of Section 19. The majority of the wells in the field are completed with 5-1/2 in. casing and 2-7/8 in. production tubing. Producers are completed on the rod pump. Injectors are completed using either a full-body tension-compression packer or a slipless inflatable packer, and set at about 1400 ft to isolate approximately one third (200 ft) of Opal A (referred to as the UD1 zone). UD1 has slightly higher porosity than the rest of the productive interval and acts as a thief zone during injection. Recently, casing side injection was separately established into the UD1 zone. Reservoir Management Plan A reservoir management plan was developed for the Exxon operated acreage to optimize field profitability and long-term recovery of reserves. Inherent to achieving this goal is the need for a clear definition of the waterflood objectives. As a result, waterflood strategies were identified and improvements implemented based on measurements and analysis of water quality, production profiles, and well injectivity. Waterflood Objectives. The objective of the waterflood in the Diatomite is to obtain secondary recovery and to mitigate subsidence. For most of the Exxon operated acreage, the majority of the primary recovery has been realized, but the secondary reserves are substantial. Maintaining pore pressure is essential in mitigating subsidence. The high porosity diatomaceous formation has low compressive strength, resulting in severe compaction as the pore pressure is decreased. Compaction is monitored by the changes in surface elevation. Fig. 1 shows the subsidence rates in the center of the Exxon property that occurred during primary production from 1979 to 1987. In 1988 to 1989, production was curtailed to reduce subsidence and casing damage while producing wells were converted to injectors. Large scale waterflooding was initiated in 1989, and most wells were returned to production. The rate of subsidence was reduced from a high of over 2 ft/yr to 0.5 ft/yr by initiating the waterflood in a portion of the productive zones (in all but the UD1 zone). Recent waterflood improvements in the past year achieved zero net voidage, further reducing the subsidence rate to about 0.2 ft/yr.