Practical Aspects of CO2 Flooding serves as a logical guide to the practicing engineer focused on the “how to” and “why” of miscible and immiscible CO2 flooding. The book outlines the entire project development sequence from conception and justification through field design and operation. Discussion centers on current and practical CO2 flooding technologies and industry experiences, and it targets those involved in planning, designing, and implementing CO2 floods. The book has five appendices including a compendium of practical, field-specific publications.

A new technique was developed to obtain reservoir descriptions to aid in the design of enhanced oil recovery (EOR) projects. This technique incorporates the reservoir performance during primary and secondary processes as well as the geological and petrophysical data. The advantage of this technique over statistical techniques is that a more realistic reservoir description can be obtained. The reservoir description when used with an EOR reservoir simulator would yield a more realistic prediction of EOR performance and minimize the risk in an EOR field project. This technique may also be used to validate a reservoir simulator for field scale EOR performance. If the reservoir description is derived independent of EOR performance, the reservoir description is based only on the reservoir heterogeneities. The EOR process variables can then be quantified from the EOR performance without changing the reservoir description (Ader and Stein). The application of this technique is illustrated for a 250 acre area of interest in a San Andres formation reservoir. The initial reservoir description is formulated based on permeability to porosity ratio plots, injection and production profiles, core data, and pressure transient tests. The initial gas saturations and pressures are obtained based on dimensionless performance curves. The reservoir description is then refined by history matching primary and secondary performance for individual wells using a reservoir simulator. For the example discussed in this paper, an excellent match of performance was achieved using this technique. Introduction To design an EOR project usually requires a characterization or description of the reservoir which can be used in a mathematical model to predict the performance of the EOR project. Because there can be significant economic risk in operating an EOR project, use of a reservoir description in a mathematical model offers a means to assess that risk. The more realistic the reservoir description is the more reliable will be the EOR performance predictions. If an EOR process is field tested prior to running a field scale EOR project, a realistic reservoir description is critical to understanding the EOR process field test and can help in validating a reservoir simulator. In addition, having a realistic reservoir description allows for studying how the various EOR process variables affect performance. Thus, the optimal design of an EOR process can be determined.

This paper details a method for determining maximum safe production rates for sand control wells. This method was developed from a thorough compilation of data from over 200 sand control wells. As a result of this analysis, a simple function of flux (fluid flow per unit area of screen) proved very reliable at separating wells operating safely from those resulting in damaged screens or unacceptable amounts of produced sand. Prior to this work, BP (and the industry) used a variety of methods to attempt to optimize production from sand control wells. Most of these prior methods use pressure drop across the completion and were loosely based on experience and rules of thumb. It is shown that these pressure based draw down limits are either ineffective for managing risk of well integrity or unnecessarily constrain well productivity. We are currently using this new flux-based approach as a basis of design for new wells and to open existing wells to a maximum safe operating production rate. Significant production addition has been added without any well failures as a result of opening up these artificially constrained wells. We furthermore anticipate preventing future well failures caused by operating at too high a rate. Earlier in 2002, two BP-operated sand control wells suffered apparent screen erosion failures; both operating at low drawdowns and safe limits using old guidelines, but at flux rates exceeding these new proposed guidelines. Introduction Most operators limit production rates in wells with a sand control completion for fear of damaging the completion and losing the well. Operators generally control these wells by maintaining a maximum pressure drawdown (reservoir pressure or shut-in bottom hole pressure minus bottom hole flowing pressure) across the completion. Maximum recommended pressure drops ranging from 500 psi to 1000 psi are common. Experience and success of nearby wells is the usual basis for determining these pressure drawdowns. Our first attempt at correlating data was to see how the data lined up with drawdown. This is presented in Figure 1. Note that the green wells (No problems) had a slightly higher average drawdown than those that failed (red) as well as a higher average drawdown than those wells constrained by sand production (yellow). (Data classification is discussed in more detail later.) It is clear that drawdown applied in this way does not help predict safe operating conditions; nor can it be used to optimize production rates. Although drawdown is not a good parameter to predict whether a sand control completion will fail or not, drawdown or pressure drop across the completion is a key parameter in determining when the sand matrix "fails" and individual sand grains can be transported by the fluid flow entering a well. This may be the basis of using drawdown to control wells with a sand control completion. Many models and predictive techniques are available to make this determination based on rock strength measurements. Depletion forces also act to weaken the sand matrix resulting in a well capable of producing sand free at high drawdowns early in well life, but failing later in life with the same or smaller drawdown after the reservoir is partially depleted. Also, just because a rock "fails" does not mean sand will be produced 1–3. Sand control completions, like frac packs and gravel packs, are designed to contain the sand whether reservoir "failure" has occurred or not. For this reason, using drawdown to control wells with effective sand control completions only makes theoretical sense when there is an ineffective or improperly installed completion in place; or in a very compressible highly depleted formation where wellbore and screen collapse is a risk. (Our data set contained only one example of a wellbore collapse and a screen crushing failure mechanism brought on by excessive depletion.) Our analysis of screen failures indicated that screen erosion was by far the most common screen failure mechanism (other than "infant" failures), even with a good quality completion in place (complete annulus pack with an undamaged and unplugged screen). Erosion of the screen is caused by fluid flow through the screen with a small amount of fine sand particles. These solids greatly accelerate erosion of the screen.

Summary A reservoir description for the Slaughter Estate Unit tertiary pilot and surrounding area and the procedure that we used to obtain it are discussed in this paper. The procedure is based on matching waterflood performance procedure is based on matching waterflood performance prior to pilot miscible gas injection with a black oil prior to pilot miscible gas injection with a black oil reservoir simulator. An initial estimate of the reservoir description is obtained from petrophysical data and single-well pressure transient tests. The initial estimate is then modified by a trial and error procedure until a good match between the actual and calculated waterflood performance is obtained. performance is obtained. It was determined that the Slaughter Estate Unit tertiary pilot had an original oil in place (OOIP) of 642,400 STB [102 133 stock-tank m3]. A waterflood prediction derived from the reservoir description in this paper indicates that a primary-plus-secondary recovery through Sept, 30, 1983, of 49.6% OOIP would have been obtained from the pilot if waterflood operations had been continued. On the basis of this prediction, it was established that the tertiary oil recovery resulting from the miscible gas process was 18.5% OOIP as of Sept. 30, 1983. Introduction The Slaughter Estate Unit tertiary pilot is one of several miscible gas EOR projects operated by Amoco Production Co. in the Permian Basin of west Texas. The pilot Production Co. in the Permian Basin of west Texas. The pilot is located in the Slaughter Estate Unit of the Slaughter field, in Hockley County. The proven productive geological zones in the Slaughter Estate Unit are designated as San Andres Zones IV, V, and VI. The unit is not influenced by a gas cap or water drive. A type log taken from Well 279 is illustrated in Fig. 1. Log-produce-log testing shows that the pilot processes San Andres Zones IV and V. The pilot configuration is a 12.3-acre, [49.8-km2] double five-spot pattern (Fig. 2). Pilot wells were drilled in mid-1972 in an area of the unit that was still under volumetric depletion. Native state cores were collected from the pilot production Well 279. A pilot waterflood program was initiated on Nov. 30, 1972. Gas collapse occurred in the pilot within 3 months after the start of water injection. A peak pilot oil-production rate of 407 STB/D [64.7 stock-tank m3/d] was measured in June 1973. By Aug. 1976 a secondary decline was established with a pilot oil-production rate of 37 STB/D [5.9 stock-tank m3/d] and a water cut of 89.5%. Acid gas (72% CO2 and 28% H2S) and water were alternately injected in the plot beginning on Aug. 23, 1976. The maximum pilot oil-production rate measured during the acid-gas injection process was 152 STB/D [24.2 stock-tank m3/d] in Feb. 1979. Chase-gas injection (residue gas or nitrogen, depending on the available supply) replaced the acid-gas injection on Oct. 16, 1979. Chase-gas injection was completed in July 1982 and the pilot has been under waterflood operations since then. In Sept. 1983 the pilot oil-production rate declined to 28 STB/D [4.5 stock-tank m3/d]. At this time, the pilot water cut (calculated for liquids only) was 96.5% and the producing GOR was 2.8 Mscf/STB [498.7 std m3/stock-tank m3]. The objectives of the pilot are to provide reservoir and performance data that are necessary to determine performance data that are necessary to determine primary-plus-secondary oil recovery, incremental primary-plus-secondary oil recovery, incremental tertiary oil recovery, and to develop a quantitative understanding of the acid-gas displacement process. This procedure will help establish the technology for reliable procedure will help establish the technology for reliable predictions of fieldwide performance for miscible gas predictions of fieldwide performance for miscible gas injection. To achieve these objectives, a good reservoir description of the pilot and the surrounding area is necessary. A reservoir description will allow for the separation of the effects of reservoir heterogeneities and miscible gas injection process variables on the tertiary pilot performance. pilot performance. Physical representation of the waterflood process in the black oil simulator is assumed to be realistic. If representative fluid and rock properties (excluding phi h, kh, and h) can be determined in the laboratory, then the only unknown quantity required to match waterflood performance is the reservoir description. History performance is the reservoir description. History matching waterflood performance by use of sound engineering principles is therefore considered a satisfactory method principles is therefore considered a satisfactory method to determine an accurate reservoir description. History matching a miscible gas flood to determine the reservoir description would not be a valid procedure because not all the physics of the miscible gas process are completely understood at this time. The first purpose of this paper is to present the reservoir description of the pilot and the procedure we used to develop it. This includes discussions of the model study area, well development history, and fluid and rock properties. A petrophysical study was combined with properties. A petrophysical study was combined with single-well pressure transient tests to provide an initial estimate of the reservoir stratification. JPT P. 837

The material balance techniques have been used in the oil and gas industry for estimating hydrocarbon reserves for a long time. The objective of this paper is to introduce a fairly simple and fast material balance technique that can provide a fairly good estimate of CO 2 storage capacity in depleted gas reservoirs.Sequestration of CO 2 in geological formations is a strategy currently being considered for decreasing CO 2 emissions to the atmosphere. These geological formations can be either depleted oil and gas reservoirs or saline reservoirs. A depleted gas reservoir can store significantly more gas than a depleted oil reservoir due to the fact that gas is more compressible than oil and the ultimate recovery in gas reservoirs is higher than that in oil reservoirs. Many researchers have published reservoir simulation studies of CO 2 sequestration in depleted gas fields, however, a reservoir simulation study, depending on its complexity, can take several months to perform. In this paper, a fairly simple and fast material balance technique, combined with nodal analysis, is presented that can provide a fairly good estimate of CO 2 storage capacity in depleted gas reservoirs.A depleted gas reservoir, for which the production and pressure history data were available, was selected as a candidate to perform this material balance study. First the material balance calculations were performed to estimate the size of the gas reservoir, aquifer and reservoir pressure. The formation parting pressure was estimated based on basic rock mechanics principles as a function of reservoir pressure. The bottom hole injection pressure was maintained below the formation parting pressure, until the surface facilities limitations were reached. As a result of this study, the amount of CO 2 that can be stored in this depleted gas reservoir was estimated within a few weeks.