Abstract To date, field wide CO 2 flooding is continuous or WAG injection processes. In individual wells a huff'n'puff scheme has been used where CO 2 is injected into a well followed by a shut-in period; after a predetermined time, the well is produced. Each of these methods have practical, technical, and economical limitations. This paper describes a new CO 2 injection method that combines all three of these methods but excludes water injection. Continuous CO 2 may be optimal in reservoirs that are not conducive to water injection and do not have CO 2 mobility control problems such as early breakthrough. However, continuous CO 2 requires a large initial CO 2 volume that may be unavailable and relatively expensive. WAG is very common with variations of different ratios of water to CO 2 volumes and tapered ratios. WAG reduces mobility problems and thereby improves areal sweep efficiency; CO 2 purchase expenses may be lower due to the requirement of lower CO 2 volumes. Unfortunately, water injectivity following CO 2 injection may decrease, and the water increases lift and water handling expenses. Huff'n'puff is effective similar to a near wellbore stimulation, but may not realize the benefits of a full field injection program. Also, this adds the complication of injection and production capabilities required in the same well. This may be impossible for some wells on artificial lift. The proposed method is to inject CO 2 and shut in the well similar to the huff and puff, but instead of producing the well inject CO 2 again. This process is a cyclic process like WAG, and shares the variables of the duration and volume of CO 2 injection and the duration of the shut-in period. This method eliminates injectivity and production expenses associated with water. Mobility is controlled by near wellbore achievement of miscibility by the increase in mass transfer between the CO 2 and oil during the shut-in portion of the cycle; i.e. a smaller portion of the reservoir has relatively low viscosity, injected CO 2 due to miscibility between oil and gas occurring nearer the injection well. Introduction The use of CO 2 as a method of enhanced oil recovery has been studied since the early 1950's 1 and its use grew signficantly in the 1970s and 1980s. 2 It is used as an enhanced oil recovery (EOR) process where it is injected following either natural drive or waterflooding in order to recover additional oil. During the life of an oil reservoir, production is usually carried out by primary recovery, secondary recovery, then enhanced oil recovery (EOR). Primary recovery uses the natural energy present in the reservoir to displace oil to the wellbore and includes solution-gas drive, gas-cap drive, natural water drive, fluid expansion, rock expansion, and gravity drainage. Secondary recovery processes add energy to the reservoir by injecting water or immiscible gas and displacing oil to an adjacent producing wellbore. However, because immiscible gases have more mobility problems than water, the secondary recovery stage is almost always carried out with a waterflood. EOR processes are carried out by gas injection, liquid chemical injection and/or the addition of thermal energy. Gas injections are considered EOR processes if the significant recovery mechanisms are not exclusively those of immiscible frontal displacement with high interfacial tension (IFT) relative permeabilities, but include such mechanisms as oil swelling, oil viscosity reduction or favorable phase behavior. The gases used in EOR processes include hydrocarbon gases, CO 2 , nitrogen, and flue gas. Liquid chemicals include polymers, surfactants, and hydrocarbon solvents. Thermal methods include steam drive, cyclic steam flooding, hot water flooding, and in situ combustion. 3

Abstract The analysis of oil production data using decline curves is a modeling and forecasting technique. Actual production rate and time data are history matched to a theoretical model using specialized graphs known as type curves. This study begins with a review of the previously developed decline curve construction and analysis methods. It consists of reproducing Arps-Fetkovich type curves and the derivative type curves for advanced decline curve analysis. A Program was developed to generate the dimensionless rate-pressure and time data necessary to construct Fetkovich type curves. Combining the analytical solution derivative for transient flow based on numerical analysis, and the empirical solution derivative for boundary dominated flow develops the derivative type curves. The type curves is used to identify the transient versus depletion stages and to estimate reservoir parameters and future decline paths. Field production data are generally difficult to match with the type curve for this reason a Universal Fitting Equation is proposed as an alternative to manual type curve matching. This equation combines both Arp's empirical equation and Fetkovich analytical solutions. It equation offer the following advantages: Fitting with the equation is more precise than type curve matching to obtain reservoir dimensionless radius reD, Arp's exponent b, matching points q/q Dd , and t Dd /t. The real production data can be fitted directly by the equation without using smoothing techniques. The radial and pseudosteady state regions are determined automatically and easily from fitting. Some production data that were insufficient to be analyzed with manual type-curve matching can be interpreted with the Fitting Equation. This procedure has been applied to some Real field data from Hassi Messaoud field cases and it has given significant results. Introduction Decline curves are the most common means of forecasting production and estimating the value of oil and gas wells. The earliest literature refers to a mathematical decline analysis approach presented by Arnold and Anderson in 1908. Arps developed the standard exponential, hyperbolic and harmonic decline equations in 1944. In 1973, Fetkovich 2 proposed a dimensionless rate-time type curve for decline curve analysis of wells producing at constant bottom-hole pressure. These type curves combined analytical solutions to the flow equations in the transient region and empirical decline curve equations in the pseudo-steady state region. This approach to decline curve analysis, known commonly referred to as "advanced decline curve analysis", has become widely used as a tool for formation evaluation and reserves estimation. In 1980, Fetkovich 2 demonstrated that decline curve analysis not only has a solid fundamental base but also provides a tool with more diagnostic power than had been previously suspected. Fetkovich 2 constructed log-log type curves, which combine all these equations developed by Arps 1 with the analytical constant pressure infinite and finite reservoir solutions. He showed that log-log type curves could be analyzed by the type curve matching technique. The uses of pressure derivatives in well test interpretation was introduced by Tiab 3 in 1975 and Bourdet et al. developed the use of derivative type curves for transient well test analysis in 1983. By multiplying the pressure derivative by the time, (or equivalently, by taking the derivative of pressure with respect to the natural log time), they were able to display both the pressure and the pressure derivative type curve on a single set of axes.

Abstract The South Swan Hills Unit, located in north-western Alberta, is a carbonate reef with an original-oil-in-place (OOIP) of approximately 850 MM bbl. Waterflooding was begun in the field during the 1960s, and a staged hydrocarbon miscible flood was begun during the 1970s. Chase gas injection was terminated in the mid-1990s. In 1994, however, miscible flooding was reinitiated in the reef margin area of the field using horizontal injectors and reduced well spacing. The reef margin is an area of thick, stacked pay that experienced high gravity override during the original miscible flood. Four patterns have been developed to date. The two earliest patterns have now completed solvent injection and are on chase waterflood. They have both recovered between 800 M bbl and 900 M bbl of incremental oil per pattern (more than 10% of pattern OOIP) from areas which were part of the original miscible flood. This paper will detail the past history of the pool under miscible flood, the redevelopment of the reef margin area using horizontal miscible injectors, and the performance of the four patterns implemented to date. The factors that have made this redevelopment successful, and their impact on field production, will also be discussed. Finally, plans for future development of this mature field will also be discussed. Introduction Hydrocarbon miscible flooding has long been a preferred means of enhanced oil recovery (EOR) in Alberta. It is similar to CO 2 flooding, with the exception that the solvent is composed of a mixture of hydrocarbon components (usually C 1 to C 5 ). The solvent is usually displaced with cheaper chase gas, composed primarily of methane. An abundance of natural gas liquids (NGLs) in the 1960s and 1970s and the opportunity to incorporate a more efficient displacement process prompted the operator of the South Swan Hills unit (SSHU) to consider a hydrocarbon miscible flood as a means to increase oil recovery. 1 An injection pilot of pure NGLs was carried out from 1970 to 1972, and the field scale project started in 1973. Initial design called for 21 patterns to be put on injection in the central and northern portion of the unit. This area was still in early stages of waterflooding, and was termed a secondary miscible flood. The western part of the unit was put on miscible injection in 1982. This area had a relatively mature waterflood, and was thus termed a tertiary miscible flood. Both areas were developed exclusively using vertical wells. Early performance, and an evaluation of the performance of the tertiary miscible flood were documented by Griffith and Cyca. 2 A common problem with miscible flooding is gravity override of the solvent due to its much lighter density at reservoir conditions than the in-situ oil and water. This was identified as a concern during the design of the original miscible flood, and was observed in the field. One area particularly prone to override was the reef margin, with its thick, continuous, stacked pay. One means of increasing recovery in miscible flood projects is to use horizontal injectors. Taber and Sereight noted several benefits that might be realized through the use of horizontal injectors including improved sweep, improved displacement efficiency, faster reservoir processing, and the minimum miscibility pressure maintained over a larger portion of the reservoir. 3 The concept of horizontal injectors applied to SSHU (and some of the other geologically similar reservoirs in the area) is illustrated in Figure 1. The horizontal well is placed low in the pay section to sweep reservoir that was missed due to gravity override during injection into vertical wells. Chugh et al describe a model study and consequent field implementation of such a miscible injector in the Virginia Hills field (a sister reservoir to SSHU) in 1997. 4

Abstract Ras Budran filed is a massive Nubian sandstone reservoir compartmentalized by major faults acting as partial barriers. Vertical communication is impeded by hydraulically sealing shale layers in the development of three main pressure regimes. A combined water injection and aquifer support the pressure. Pre-mature water breakthrough has been occurred in the middle of oil leg, which in turn limit the corrective action of the isolation of the watered out zones. 3D- geological and reservoir simulation model was constructed, based upon new reservoir characterization with the objective of improving the vertical definitions within the reservoir. The reservoir properties generated by deterministic interpretation for the new micro-zones. This paper presents the approach taken to match 17 years of production data in particular, via aquifer definition and fault communication. The history-matched model was then used to confidently check the production and injection well pattern and performance. The matched model then used to investigate the viability of infill wells to improve drainage pattern and sweep efficiency meanwhile increasing ultimate recovery. Introduction Ras Budran field (R/B) is located at the eastern coast of the Gulf of Suez area (Fig 1). The field was discovered in April 1978 and production started in Feb., 1983. Production is maintained by gas lifting while the pressure is supported by a combined water flooding and limited aquifer drive. There are 17 producing wells and 4 injectors over 3 offshore platforms. The field is relatively deep reservoir with the original oil water contact at 12350 ft-tvdss. Heavily under saturated reservoir with initial reservoir pressure of 5632 psia and the bubble point pressure 1200 psia. The structure contour map Fig. (2) shows the reservoir complexity. The reservoir is massive sandstone and the macro layers were defined from top to bottom as follows; Raha, Nubian III, IIB, IIA and Unit I. Unit IIA has a shale/sand streaks that work as a vertical hydraulic barrier between the upper and lower units. Lower Units of block, which called Unit I (LA), Upper units of block A (UA), Upper Units of block B (UB) and Upper Units of block C (UC). Fluid flow in the reservoir is directed from unit I to the juxtaposed upper reservoir units supported by water injection in unit I from injector A3b and direct aquifer support. Fluid flow in upper units of block A is only supported by the water injection through injectors A2, A1 and A9 respectively. Fig (3) illustrates the main cross section for the field. Due to the nature of Ras Budran reservoir and its dipping structure, peripheral injection pattern was proposed and implemented in the original field development plans in October 1985 through two wells A2a (Unit IIB+III+R), and A3b (Unit I). In January 1990, the system was upgraded with another injector A1 (Units IIB+III), to replace the poor injector A2a and finally, the last injector A9a (Units IIB+III+R) was brought on line in April 1992. The difference between formation and injection seawater salinity was used as a tool to monitor the flood front and the interblock communication. The field has already produced 80% from the estimated reserves. Modeling History: Because it will not be possible to capture the dynamics of a water flood project, in particular with high mobility ratios as in the case of Ras Budran, with single cell calculations. Reservoir simulation modeling is essential in order to optimize injection/production well patterns and to optimize sweep efficiency via the injection distribution.

Abstract This paper is a two-part discussion describing Glass Reinforced Epoxy composite linings manufactured and installed in oilfield tubular goods where the material functions as a barrier to corrosion. The paper first focuses on GRE composites in terms of effectiveness and product life compared with less-costly corrosion solutions (such as internal plastic coatings (IPC) and thermoplastic materials like HDPE and PVC). Next, actual case history economic data is presented to qualify the use of Glass Reinforced Epoxy-lined tubular goods over IPC for corrosive seawater injection service in the North Sea. These data are then extrapolated to construct a similar economic model based on workover costs in the Permian basin of West Texas. Additionally, net present value (NPV) analysis can be used to illustrate the saving s in long term operating costs over the life of the project. Introduction Though used extensively worldwide, GRE composite-lined tubular goods have demonstrated an especially wide acceptance in the Permian Basin of West Texas and eastern New Mexico as injection tubing for secondary and tertiary recovery of oil where injected formation water and CO 2 combine to form some of the world's most corrosive downhole environments. This acceptance is a direct function of the material's durability and long product life. Although GRE-lined tubular goods are most commonly used in corrosive service where the downhole temperature is below 300° Fahrenheit, novel manufacturing techniques have enabled tolerance of higher temperatures and generally harsher environments. This ultimately provides the end user a lower cost alternative to expensive steel alloys and opens up new opportunities in corrosive gas production and gas-lifted oil production where previously chromium-nickel alloys have been the exclusive choices. The new generation of GRE-lined tubular products can now be reasonably utilized in deep gas production and corrosive high-temperature injection on land and in offshore environments. A major North Sea operator qualified GRE linings over internal plastic coating for seawater injection. This qualification was premised on favorable workover economics made possible by the increased product life of GRE as opposed to that of IPC. Use of GRE-lined injection tubing resulted in substantial savings of funds that would have been spent for high-cost workovers and material replacement costs. When Net Present Value (NPV) of these savings are compared to the higher capital expense to specify the premium material (vs. selection of the less durable, lower costing material) the fundamentals of this model are born out in all environments. The Cost of Corrosion The impact of corrosion throughout nearly every industry in business today is devastating. NACE estimates that $300 Billion per year is subtracted from U.S. industrial operations alone. About $150 Billion of these costs can be prevented by various forms of corrosion engineering and project planning (1). It is estimated that tubular corrosion by itself costs the oil and gas industry billions of dollars per year. Kermani and Harrop define the cost of corrosion to the oil and gas industry in terms of capital expenditure and operating expenditure and also point out the costs to HSE (Health, Safety and Environment) relative to oilfield corrosion (2). Four cost categories are identified as follows: The cost of designing corrosion control into the project (Capex) . For example, costs in this category are incurred where specialty metals and materials are purchased to avoid corrosion. The premium paid for GRE lining would fall into this category. The cost of maintaining and repairing corrosion-damaged equipment (Opex). The recurring costs of chemical maintenance or the occasional workover unit operation costs are examples of operating expense incurred due to corrosion.

Abstract This paper describes a straightforward strategy for diagnosing and solving excess water production problems. The strategy advocates that the easiest problems should be attacked first and diagnosis of water production problems should begin with information already at hand. A listing of water production problems is provided, along with a ranking of their relative ease of solution. Conventional methods (e.g., cement, mechanical devices) normally should be applied first to treat the easiest problems-i.e., casing leaks and flow behind pipe where cement can be placed effectively and for unfractured wells where impermeable barriers separate water and hydrocarbon zones. Gelant treatments normally are the best option for casing leaks and flow behind pipe with flow restrictions that prevent effective cement placement. Both gelants and preformed gels have been successfully applied to treat hydraulic or natural fractures that connect to an aquifer. Treatments with preformed gels normally are the best option for faults or fractures crossing a deviated or horizontal well, for a single fracture causing channeling between wells, or for a natural fracture system that allows channeling between wells. Gel treatments should not be used to treat the most difficult problems—i.e., three-dimensional coning, cusping, or channeling through strata with crossflow. Introduction On average in the United States, more than seven barrels of water are produced for each barrel of oil. 1 Worldwide, an average of three barrels of water are produced for each barrel of oil. 2 The annual cost of disposing of this water is estimated to be 5–10 billion dollars in the US and around 40 billion dollars worldwide. 2 Many different causes of excess water production exist (Table 1). Each of these problems requires a different approach to find the optimum solution. Therefore, to achieve a high success rate when treating water production problems, the nature of the problem must first be correctly identified. 3 Many different materials and methods can be used to attack excess water production problems. Generally, these methods can be categorized as chemical or mechanical (see Table 2). Each of these methods may work very well for certain types of problems but are usually ineffective for other types of problems. Again, for effective treatment, the nature of the problem must first be correctly identified. Four problem categories are listed in Table 1 in the general order of increasing treatment difficulty. Within each category, the order of listing is only roughly related to the degree of treatment difficulty. Category A, "Conventional" Treatments Normally Are an Effective Choice, includes the application of water shutoff techniques that are generally well established, utilize materials with high mechanical strength, and function in or very near the wellbore. Examples include Portland cement, mechanical tubing patches, bridge plugs, straddle packers, and wellbore sand plugs. A few comments may be helpful to clarify some of the listings in Table 1. First, the difference between Problems 1 and 4 is simply a matter of aperture size of the casing leak and size of the flow channel behind the casing leak. Problem 1, involving casing leaks without flow restrictions, is where the leak is occurring through a large aperture breach in the piping (greater than roughly 1/8 in.) and a large flow conduit (greater than roughly 1/16 in.) behind the leak. The use of Portland cement is favored for treating Problem 1. Problem 4, involving casing leaks with flow restrictions, is where the leak is occurring through a small aperture breach (e.g., "pinhole" and tread leaks) in the piping (less than roughly 1/8 in.) and a small flow conduit (less than roughly 1/16 in.) behind the leak. The use of gel is favored to successfully treat Problem 4. In this paper, the gels under discussion may include those formed from chemically crosslinking water-soluble organic polymers, water-based organic monomers, or silicates.

Abstract A team was formed to solve field-wide conformance problems in a San Andres (dolomite) unit of the Slaughter Field, Hockley Co., Texas. The team's goal was to increase oil production and decrease production costs by understanding fluid movement through the reservoir. The team was comprised of operating and service company personnel who performed data analysis, and developed engineering and solution designs. The reservoir conformance team identified, quantified, and fully described field conformance problems. Team members focused on understanding fluid movement through the total reservoir rather than on single wells. They developed a framework of data for designing successful conformance solutions. This framework includes data about the reservoir, completion design, drilling and workover history, production and well-test history, logs, diagnostic analysis, and placement options. The framework serves as a data-collection tool and as a tool for identifying missing data. 1 This project involves the following tasks: analyzing approximately 300 wells, identifying conformance candidate (pilot) wells, implementing the pilot wells, analyzing the results from the pilot wells, and applying those results to the rest of the unit. In this project, team members developed the typical data analysis, reservoir and production engineering proposals, and solutions proposals, and also thoroughly reviewed the customer's economic drivers. In these mature units, enhancing recovery and production rates and reducing costs were important factors. Treatments have been placed and analyzed for sweep improvement, CO 2 reduction, and water cycling-breakthroughs. Introduction In early 1998, Occidental Permian, Ltd. (OPL) realized that, to make their large CO 2 floods and waterfloods more financially viable, they needed to address conformance issues. OPL joined Halliburton Energy Services, Inc. (HES) to form a team for addressing conformance issues and for developing the step-function change. The Slaughter Field in Hockley Co., Texas (approximately 40 miles west of Lubbock) is comprised of several units producing from the San Andres dolomite. Typical completion depths are 4,000 to 5,500 ft. This layered, highly dolomitized reservoir has significant permeability variations. The typical unit in this field has been on water flood for over 30 years, and many units have been on CO 2 WAG for over 15 years. One of these WAG units was chosen as the focus of this project. The Central Mallet Unit (CMU) operated by OPL is located in the Slaughter Field. Production is from the Permian-aged San Andres dolomite. The CMU produces from an average reservoir depth of ±5,100 ft. The field was discovered in 1937 and unitized in February 1964, with full-scale water injection beginning shortly thereafter. CO 2 injection began in December 1984. The wells in the CMU are completed with approximately 150 ft of 4 3/4-in. open hole, which increased the difficulty of choosing an appropriate placement technique. The CMU was developed with "chicken wire" patterns, or a diagonal line drive in which producers and injectors line up along the WNW to ESE fracture trend. This development has led to many injectors communicating directly to the offset producers, which became even more evident when CO 2 operations began in late 1984. Because of poor conformance results, producers began controlling gas breakthrough by reducing the gas-injection rate and altering the gas-to-water ratio (GWR). If these changes failed to control the gas volume being produced, the offending injector was then put on continuous water injection. A current study proposes pattern realignment, which could be a longer-term solution to the conformance problem despite its expense.

Abstract The cessation of CO 2 injection may be the result of poorreservoir response, low oil prices, or near the end of a CO 2 project. The focus of this paper is to describe the effect ofCO 2 injection curtailment on oil recovery and production in atechnically successful CO 2 flood of an oil reservoir. TheCO 2 curtailment is sustained over a significant period of time whilewater is injected. Following the curtailment, CO 2 is againinjected. Early EOR literature covers CO 2 and miscible gas injection in thepresence of very high water saturation. The key issues are phasebehavior, surface tension, viscosity, and oil stripping, which are described interms of curtailment and the subsequent affect on oil production. A survey of pertinent literature has been conducted to infer the impactCO 2 curtailment has on reservoir performance. Preliminaryfindings are that the curtailment of CO 2 leads to a permanent lossin reserves and production rate. Scenarios that may alleviate theselosses such as reduced CO 2 injection instead of complete curtailmentare addressed. Introduction A CO 2 flood may become uneconomic due to high operation costs orlow oil prices. Due to the expense of purchasing CO 2 forinjection, CO 2 purchases may be halted until a more favorableeconomic situation exists. The effects of curtailing CO 2 injection, replacing it with water injection for a significant period of time, and then starting CO 2 at a later time is the subject of thispaper. An analogy to curtailment is injecting CO 2 at initially highwater saturations, which has been studied extensively in the literature due toearly concerns of the effectiveness of CO 2 to mobilize waterfloodresidual oil. The key issues are wettability, solubility ofCO 2 in water, phase behavior (miscibility), diffusion, dispersion(viscous fingers), and oil bank formation. In an attempt to understand the technical aspects of CO 2 curtailment, field case publications were intentionally not included.While this work has not been previously published, it was first presented atthe 1999 CO 2 Conference in Midland.

Abstract Aimed for the need of oil displacement in high salinity formations where the normal nonionic and anionic surfactants are inefficient because of salting out or cloud point phenomena [1] , A novel structure surfactant(LF) with nonionic and anionic hydrophilic group is put forward and synthesized. The said surfactant is soluble in 30% NaCl brine, and shows good surface activity in brine with 100,000mg/L salinity concluding 5,000mg/L CaCl 2 . By analysizing the volume fraction-salt concentration phase graph, the salt tolerance property of LF, petroleum sulfonate and their combined system is comparatively studied, LF is excellent, the proportional increment of LF in combined system will improves salt tolerance property of the combined system. In any different brine, water/n-decane Interfacial tension is high if only LF or petroleum sulfonate is used, but Interfacial tension will reach super low if the combined system is appropriately used as long as water salinity is enough high(higher than 20,000mg/L). By adjusting the proportion of LF and petroleum sulfonate in combined system, water/oil Interfacial tension can always reach super low regardless of water salinity, so the system can be particularly used as oil displacement agent in high salinity formations. The paper presents three oil displacement and one chemical tuff and puff formulations consisted of LF and KPS, which were suitable for high salinity formations in Zhongyuan oil field. The temperatures of four test zone are 86.9°C, 65.0°C, 82.5°C and 82.5°C, the salinities are 88,540 mg/L, 55,028 mg/L, 14,9127mg/L and 195,000 mg/L, the room recovery improvement all exceed 19%. Now the four field tests get along favorably, verifying good result and indicating bright application prospect. Introduction Surfactants are widely used in oil field, and the interest in the use of nonionic and anionic surfactants has increased, For example, polyoxyethylenated alkyl alcohol and petroleum sulfonate(PS), but they cannot be used in high temperature and high salinity formations. Nonionic surfactants and anionic surfactants will salt out because of cloud point phenomena and high salinity respectively. Therefore, a novel structure surfactant (LF) with nonionic and anionic hydrophilic group is put forward, it will not only maintain the advantages of nonionic and anionic surfactant, but also overcome the inefficiency [1–4] . In the work, ether caxhoxylated surfactant, as a nonionic and anionic ampholytic surfactant, was industrially acquired, it revealed that the nonionic group is oxyethylene and the anionic group is carboxyl. The structural formula is as follows: C 9 H 19 -C 6 H 4 -O- (CH 2 CH 2 O) 8 -CH 2 COONa C 6 H 4 refer to arykyl. Experimental Method Surface tension is measured by vertical plate method. Interfacial tension is measured by the Texas-500 spinning drop interfacial tensiometer, and the value of water/oil interfacial tension is determined with 0.2% concentration of surfactant.

Abstract CO 2 miscible gas flooding is a popular method of improved oil recovery. It is widely used in the Permian Basin. Asphaltene deposition in many of these systems is a costly operational problem associated with the utilization of this method of recovery. A CO 2 flood in West Texas was experiencing major problems with asphaltene deposition related ESP failures and tubing plugging. Operational procedures, field experience and a successful chemical program have greatly reduced the cost of these problems over the last 3 years. A new inhibitor for continuous capillary injection was recently developed and performed well on live oil lab tests. To evaluate the field performance of this new asphaltene inhibitor, a wellhead side stream filter loop was constructed to monitor asphaltene precipitation/deposition. The objective was to measure and compare the time needed to plug a given size filter with untreated and chemical treated produced fluids. Pressure data at the filter loop and wellhead was also recorded to monitor the effectiveness of the treatments. The field trial results proved the use of a filter-plugging side stream was an effective way of assessing asphaltene inhibitor performance. Based on the filter plugging and wellhead pressure data, it was concluded that asphaltene precipitation/deposition occurred if the produced fluid was not chemically treated. The standard field product used successfully in the past was able to reduce asphaltene deposition and doubled the filter plugging time. The new asphaltene inhibitor was shown to be more effective for stabilizing the asphaltenes in the CO 2 flooded produced fluids. The new inhibitor extended the time needed to plug a filter by more than four times as compared to untreated fluids. Case history information, laboratory tests results, side stream configuration, field test procedure and field test results are presented. Introduction Asphaltenes are heterocyclic unsaturated macromolecules consisting primarily of carbon, hydrogen, and a minor proportion of heteroelements such as oxygen, sulfur, nitrogen etc 1,2 . The amounts of carbon and hydrogen in asphaltenes vary over a very small range so that the H/C ratio is fairly constant at about 1.1–1.2, which is characteristic of a strong aromatic composition. Asphaltenes are typically defined by solubility as benzene soluble and pentane or heptane insoluble 1,2,3 . The asphaltenes are believed to exist in the oil as a colloidal suspension, and are stabilized by resins adsorbed on their surface 1 . These higher molecular weight components of crude oil are normally in equilibrium at reservoir condition. As crude oil is produced this equilibrium may be disrupted by a number of factors including pressure reductions, crude oil chemical composition changes, introduction of miscible gases and liquids, mixing with diluents and other oils, and during acid stimulation, hot oiling and other oilfield operations. The upset of the colloidal system may result in irreversible flocculation of asphaltenes. The deposition and precipitation of flocculated asphaltenes can severely reduce the permeability of the reservoir, cause formation damage and can also plug-up the wellbore and tubing. The two primary mechanisms for asphaltene flocculation and deposition are depressurizing of the oil and mixing of solvents with reservoir oil during enhanced oil recovery (EOR).

Abstract Heterogeneous reservoirs undergoing waterflooding contain low- permeability zones in which oil in the low-permeability zones is bypassed by water. Profitability of producing from heterogeneous reservoirs can be poor because of premature water-breakthrough through high-permeability layers. It seems possible to improve the profitability of producing from heterogeneous reservoirs by diverting the injected water from preferentially flowing through high to low-permeability zones. The profitability improves because of a small increase in ultimate oil recovery and/or a large reduction in cumulative water production. The objective of this study is to investigate the applicability of the technology, referred to as indirect waterflooding, in different types of heterogeneous reservoirs. We performed numerical simulations of waterfloods on a generic five-spot pattern for three different reservoir cases. The reservoirs had properties typical of a San Andres Formation. The first case, with vertical-heterogeneity, showed that ultimate oil recovery might be improved by up to 13% OOIP with indirect waterflooding. The second case, with areal-heterogeneity and a low k v /k h , showed that water production might be reduced by as much as 27%. The third case, with areal heterogeneity and a zero k v /k h , showed that water production might be reduced by 31%. Actual recoveries are sensitive to reservoir properties, especially in the magnitude of the vertical permeability. Introduction Most reservoirs consist of rocks with a broad spectrum of permeabilities. However, to explain the proposed technology (indirect waterflooding), we imagine two types of rock, a high-permeability zone, through which fluid flows readily, and a low-permeability zone. The low-permeability zone may have slightly smaller initial oil saturation than the high-permeability zone, but both zones are initially oil saturated. Previously drilled vertical wells penetrate both zones. Historically, oil recoveries during primary recovery are typically less than 10%. This percentage is reasonable given that the primary production mechanism in San Andres reservoirs is mainly by solution gas drive. In fact, one can make the case that the primary recovery, as low as it is, is greater than it should be, because of reservoir heterogeneity. Figure 1 illustrates a possible reason for this. During primary production, oil drains directly to producing wells; however, a substantial amount of oil drains from the low-permeability zone to the high-permeability zone (and is thereby produced) because of the different rates of pressure declines in the two zones. We will call this indirect depletion. Even if the pressure difference between the low and high-permeability zones is small, the indirect depletion (crossflow) can be substantial because the contact area between the two zones is large. In fact, the existence of this large contact area, in contrast to the normally very small contact area between the low-permeability zone and the wells penetrating it, means that the indirect depletion can be larger than the direct depletion into the wells from the low-permeability zone.

Abstract The crosshole EM technique provides an image analogous to a smoothed two-dimensional induction resistivity log. Inductive EM sources are placed in one well and magnetic field receivers in a second well, up to a km away. Sources and receivers are positioned above within and below the depth interval of interest, and we image the resistivity of the interwell volume to fit the collected data. Data may be collected in open and/or steel-cased boreholes, although steel casing reduces this range. The resolution of images is roughly 5 percent of the well spacing. The technique has been used for more than 5 years in imaging thermal oil recovery operations, but more recently for reservoir characterization and water flood imaging. The resistivity contrast between salt water saturated zones and oil and gas pay zones usually provides an excellent signal for the EM data and makes the imaging of the water flood fairly straightforward. In this paper we provide a technology overview and then show a case history where the EM resistivity images have defined the initial water saturation distribution, and have tracked changes over a two year period due to water flooding in a fracture dominated southern California reservoir. We further describe simulations for crosshole EM imaging in carbonates for a WAG (water alternating gas) process where the technique is used for initial site characterization and to monitor saturation changes during the injection. Introduction With the advent of crosshole seismic technology in the 1980's a new generation of high resolution geophysical tools has become available for reservoir characterization and process monitoring. The chief improvement over other methods is simply that the tools are deployed in boreholes which enables the measurements to take place much closer to the region of interest. Beginning in 1990 researchers began development of a low frequency crosshole EM technology (3). The crosshole EM induction system can be thought of as an extension of the borehole induction logs into the region between wells. The system, in fact, operates very similar to single well logging tools but with the transmitter and receiver tools deployed in separate boreholes. Figure 1 provides an excellent illustration of why field developers should consider collecting EM in addition to seismic data. Here we plot seismic velocity and electrical resistivity as a function of porosity, water saturation and temperature in water flooded sandstone cores. The plots indicate a high sensitivity of the electrical resistivity to variations in reservoir conditions, and a smaller sensitivity of seismic velocity to the same reservoir variations. Typically, the resistivity varies up to an order of magnitude over the range of typical reservoir conditions whereas the seismic velocities vary by no more than 10 to 20 percent. The contrast is most pronounced in Figure 1b where the seismic data indicate a very small change due to fluid saturation whereas the electrical data are greatly affected. This above plot is not surprising considering the physics. Seismic waves are predominantly supported by the rock matrix and variations due to pore fluids are secondary effects. EM induced currents primarily flow in the pore fluids, electrical property variations of these fluids therefore have a large effect on EM data. The combination of the two techniques thereby allows high definition of both the rock matrix and pore fluids.

Abstract Analysis of numerous injection/falloff tests in the field, primarily on coalbed methane wells, has led to a better understanding of the requirements for proper injection/falloff testing. Because most of the formations do not flow prior to testing, test design is difficult and many of the testing procedures must be modified during the test itself. If a testing program is not carefully designed and implemented, erroneous results for permeability and skin factor can be obtained, even though the analysis results appear reasonable. This paper outlines some general guidelines for injection/falloff testing of coalbed methane and other low permeability reservoirs. Using several field-based examples, potential analysis pitfalls are highlighted including 1) injection above fracture pressure, 2) non-stable reservoir pressure prior to testing, and 3) a poor connection between the wellbore and reservoir. Any of these conditions may result in pressure responses which appear analyzable, but which give misleading or erroneous results. P. 197

Abstract Carbon dioxide injection in the Dollarhide Devonian reservoir commenced in May 1985. Subsequently, CO injection was expanded to an area of the majority southern fault block. As of May 1995, CO injection has been implemented in the entire Devonian formation in five phases. Hybrid CO injection was chosen to be the primary mode of operation. During the course of this project, the operator experienced reduction in injectivity when switching to WAG after injecting a 10% hydrocarbon pore volume CO slug in phases 1 and 2. Oil production consequently decreased due to reduced injectivity. This study was designed to answer operation related questions. We selected a 5-spot pattern in the southern fault block for this study partly because it had the longest production history with hybrid CO injection, and also because the study area was not complicated by faults. Forecasts were made over a period of twenty years for four scenarios. The cause of sustained high water cut at the central producer was also investigated. A fine grid model was used in this study in order to compare more accurately the recovery efficiencies between a single CO slug and hybrid CO injection, and to investigate the advantages of operating at a lower pressure. P. 319

Abstract A pilot area in the East Vacuum Grayburg-San Anders Unit (EVGSAU) was selected for a comprehensive evaluation of the use of foam for improving the effectiveness of a CO flood. The response from the foam field trial was very positive, it successfully demonstrated that field application of CO-foam is a technical viable process for improved oil recovery (IOR). A pseudo-miscible reservoir simulator, MASTER, which was recently modified by incorporating a newly developed foam model, was used to conduct a history match study on the pilot area at EVGSAU to understand the process mechanisms and sensitive parameters. The ultimate purpose was to establish a foam predictive model for CO- foam processes. In this paper, the history match results are presented. The important modeling considerations that led to an acceptable history match are highlighted and discussed. Finally, the simulated results of a foam predictive ease are presented. The injection schedule of the foam predictive ease was specifically selected to mimic the filed injection schedule used in the foam pilot test at EVGSAU. The simulated results are consistent with the field pilot test results. Overall, the foam model is found to be adequate for field scale CO-foam simulation. The results also confirm that the communication path between the foam injection well and the offending well had a strong impact on the production performance. P. 365

Abstract This paper considers some of the reservoir variables that affect the severity of channeling and the potential of gel treatments for reducing channeling through naturally fractured reservoirs. We performed extensive tracer and gel placement studies using two different simulators. We show that gel treatments have the greatest potential when the conductivities of fractures that are aligned with direct flow between an injector-producer pair are at least 10 times the conductivity of off-trend fractures. Gel treatments also have their greatest potential in reservoirs with moderate to large fracture spacing. Produced tracer concentrations from interwell tracer studies can help identify reservoirs that are predisposed to successful gel applications. Our simulation studies also show how tracer transit times can be used to estimate the conductivity of the most direct fracture. The effectiveness of gel treatments should be insensitive to fracture spacing for fractures that are aligned with the direct flow direction. The effectiveness of gel treatments increases with increased fracture spacing for fractures that are not aligned with the direct flow direction. P. 419

Abstract The Ford Geraldine Unit (FGU), in Reeves and Culberson Counties, West Texas, produces from the Ramsey Sandstone in the upper Bell Canyon Formation. After primary depletion, a major portion of the reservoir was waterflooded in stages from 1969 to 1980 and is currently under a maturing CO flood that was started in 1981. However, because of high initial water saturation of 47.7% and some aquifer encroachment, the structurally low areas in the northeastern part of the reservoir were producing at very high water cut when the primary recovery approached its economic limit in 1968. As a result, this area responded very poorly to waterflood and no significant production has since been realized from this part of the unit. An estimated 10.1 MMSTB of the 12.9 MMSTB original oil in place (OOIP) remains in the reservoir in this area. This paper presents results of a study in which advanced geologic, geophysical, and engineering reservoir characterization techniques have been applied to this part of the reservoir as a demonstration area for enhanced recovery. A conditionally simulated Stochastic-permeability-distribution model has also been developed. Compositional simulations were performed for CO flood using stochastic and layered permeability distributions and conservative estimates of fluid saturations. Results indicate that a minimum of 10% of remaining oil in place (ROIP) can be recovered at breakthrough. Despite very high postwaterflood water saturations, the producing water cut gradually declines because of increase in hydrocarbon mobility as the injected CO dissolves in the oil. An important observation is that compositional simulations indicate significant incremental recovery after breakthrough. At the permissible gas-oil ratio (GOR) of 30 MSCF/STB, recovery of over 30% of ROIP is achievable from the demonstration area. P. 375

Abstract This paper describes the reservoir engineering aspects of the CO feasibility study for Department of Energy Class II project, at the West Welch San Anders Unit. The DOE Class II demonstration simulation effort for the CO feasibility study uses an 11 component equation of state (EOS) for surface facility design. Relative permeability data measured in the laboratory indicated two different waterflood residual oil saturations. The low reservoir temperature causes the fluid phase behavior to exhibit a two liquid hydrocarbon phase region with CO present Fluid characterization steps taken to virtually eliminate the two liquid hydrocarbon phase region is described. The problems these changes created and adjustments made to the EOS to improve the simulation are reviewed. We show that the EOS needs to predict slim tube recovery compositions as well as the total slim tube recovery to adequately predict field scale oil recovery. The fluid characterization procedure, described here, made the full field simulations more closely match field CO recovery. Two types of wettability were identified from relative permeability curves at the project in the Welch field. The intervals of different wettability were identified from resistivity logs to aid in placing these intervals in the proper model layers. The geologic model with both relative permeability rock types led to overpredicting oil recovery. However, the low waterflood residual oil saturation appears more significant in the higher permeability rock. Thus, the relative permeability tests from core samples with higher permeability led to significant differences in model results. Subsequent history matching efforts, incorporating 3D seismic, showed that the relative permeability rock type with low residual oil saturation to water was not volumetrically significant. A separate paper, SPE 39809, describes the incorporation of 3Dseismic into the geologic model. P. 489

This paper was prepared for presentation at the 1998 SPE Permian Basin Oil and Gas Recovery Conference held in Midland, Texas, 25-27 March 1998.

Abstract Conformance control is any action taken to improve the injection or production profile of a well. It encompasses procedures that enhance recovery efficiency, improve wellbore/casing integrity, and satisfy environmental regulations. Unwanted fluid production in oil- and gas-producing wells is a limiting factor that controls the productive life of a well. The cost of produced water disposal in an environmentally non-threatening fashion may be a major concern for many producers. In addition, control of excess water and gas production improves profitability by allowing additional oil to be produced. Application of water control technology assists to minimize water production and maintain the oil flow rate of a well. Reservoir engineering and well testing play essential roles in characterizing and detecting the problems associated with producing formations and wells. This paper starts with problem identification in both producing and injection wells. It then covers the behavior and control of several types of reservoirs with different drive mechanisms. Applications of reservoir simulation and well testing in the control of water and gas coning, determination of the amount and the best appropriate treatment application, effect of formation layering, control of relative permeability to water, application of permeability blocking agents, water channeling, secondary recovery, viscous fingering, and polymer flooding are detailed in this paper. In additional several techniques to evaluate the overall success of a conformance control procedure are presented. Introduction The purpose of this paper is to identify reservoirs associated with excessive gas or water production and to recommend the proper remediation. Conformance control begins with identifying the source of problem. This requires a thorough investigation of all aspects of well and reservoir parameters. The following is a list of some of the parameters required for identification of the reservoir performance problems. Reservoir permeability and porosity Relative permeability to oil, water, and gas Connate water and irreducible oil and gas saturations Net formation height Recovery mechanism Reservoir dip Oil, gas, and water production rates versus time Original water-oil contact Length of time before water production began Location of all perforations Fraction of the productive interval completed Identification of fluid entry locations and the type of fluid entering wellbore (production logging) Location and continuity of any shale layers Identification of cement to casing bonding (bond log)