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Collaborating Authors
Results
Pilot Test of Alkaline Surfactant Polymer Flooding in Daqing Oil Field
Demin, Wang (Daqing Petroleum Administration Bureau P.R.C.) | Zhenhua, Zhang (Daqing Petroleum Administration Bureau P.R.C.) | Jiecheng, Cheng (Daqing Petroleum Administration Bureau P.R.C.) | Jingchun, Yang (Daqing Petroleum Administration Bureau P.R.C.) | Shutang, Gao (Daqing Petroleum Administration Bureau P.R.C.) | Li, Lin (Daqing Petroleum Administration Bureau P.R.C.)
Summary After the success of polymer flooding in Daqing, two alkaline/surfactant/polymer (ASP) floods were conducted to increase oil recovery further, to study the feasibility of ASP flooding, and to provide technical and practical experience for expanding the ASP pilots. The crude oil of both pilots has a high paraffin content and low acid value. After extensive screening, an ASP system with very low surfactant concentration and wide range of ultralow interfacial tension (IFT) with any concentration change of the three components was determined for each pilot. Coreflooding and numerical simulation show more than 20% original-oil-in-place (OOIP) incremental recovery by ASP over waterflooding for both pilots. The ASP flood pilot tests are technically successful and, on the basis of preliminary evaluation, economically feasible; therefore, much larger-scale ASP-flooding field tests are planned in Daqing oil field in the near future. Introduction A polymer-flooding pilot test and a commercial field test have been conducted successfully in the Daqing oil field, and large-scale commercial application is now in process. To improve oil recovery and displacement efficiency further, surfactant/polymer- and micellar/polymer-flooding pilot tests have been conducted. All the tests achieved good technological results. Because of the high cost of use of large quantities of surfactants, this technology has not been expanded. ASP flooding can enlarge swept volume, improve the water/oil mobility ratio, and greatly improve displacement efficiency. Pilot tests of ASP flooding have been conducted, and good results achieved for high-acid-value crude oil; however, no pilot tests have been reported in reservoirs with low-acid-value crude oil. The acid value of crude oil in Daqing oil field is 0.1 mg/g KOH. We conducted ASP flooding research in laboratory and obtained good results. On the basis of the specific reservoir characteristics in north and south of Daqing oil field, two ASP-flood formulations were selected and pilot tests were conducted.
- Asia > China > Heilongjiang > Songliao Basin > Saertu Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Summary During gas injection, bypassing of oil is common because of gravitational, viscous, and/or heterogeneity effects. The oil in the bypassed regions can be recovered through enhanced flow and mass transfer between the bypassed region and the injectant gas. Previously, experiments in our laboratory have been carried out to evaluate the effects of phase behavior and capillary crossflow in near-miscible gasfloods; however, these studies were conducted in the absence of water. In this paper, we evaluate the effects of water saturation on oil bypassing and the rate of mass transfer from the bypassed zones. Injectant gases are first-contact miscible (FCM), multicontact miscible (MCM), or submiscible with the bypassed oil. Gasfloods are conducted in different orientations with different levels of water saturation. Mass-transfer experiments are carried out to isolate and investigate mass-transfer mechanisms. Results indicate that oil recovery from vertical, submiscible gasfloods is not influenced by water-saturation level. Horizontal gasfloods showed evidence of less gravity override in the presence of water. The mass-transfer experiments showed that recovery increases with enrichment and is reduced by the presence of water. Effective diffusion coefficients are estimated as functions of water saturation and enrichment. Introduction Near-miscible gasflood refers to injection of gases that do not quite develop complete miscibility with the oil, but come close. For example, condensing/vaporizing gasdrives and gasfloods at enrichments slightly below minimum miscibility enrichment (MME) or at pressures slightly below minimum miscibility pressure (MMP) are near miscible. Miscible and near-miscible gasfloods are being conducted or considered in many oil reservoirs. Miscible gas injections are also being considered for many fractured oil reservoirs. Bypassing of large quantities of oil can occur during gas injections because of formation heterogeneity, gravity override, and viscous fingering. A significant fraction of this oil can be recovered by subsequent mass transfer from the bypassed regions. It is important to identify factors that affect bypassing and mass transfer and develop processes that minimize bypassing and maximize the subsequent mass transfer.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Summary A gravity-stable, vertical CO2-miscible-injection flood was implemented in the 824-ft-thick Wellman Unit Wolfcamp reef reservoir in July 1983. CO2 is injected in the crest of the reservoir to displace the oil vertically downward. The producing wells are constantly plugged down out of the "gassed-out" interval into the oil bank. This paper presents the results of the PNDยฎ-S through-tubing logging tool as a method to determine the CO2/oil/water contacts and the use of multiple-inflatable-packer/sliding-sleeve plugdown assemblies to achieve zonal isolation between gassed-out and producing intervals. Introduction The Wellman field is a limestone reef reservoir located in Terry County, Texas, in the western part of the Midland basin. The Wellman structure shown in Fig. 1 is a bioherm reef with a maximum closure of 824 ft above the original oil/water contact (OWC) at 6,680 ft subsea. The reef is oval shaped and approximately 1.8 miles long and 1.4 miles wide, covering a productive area of 1,306 acres. A recent model study indicates that the reservoir contained 122 MMSTB of highly undersaturated oil in place. Table 1 presents a summary of the reservoir and fluid properties at the original as well as current operating conditions. This data are very similar to previous reported reservoir properties. The Wellman field was discovered in July 1950 and was produced under primary depletion until 1979, when a water-injection project was initiated. Water injection for pressure maintenance was initiated into the lower part of the reef just above the original OWC to displace the oil vertically upward. Water production in both the primary and secondary phases was controlled by recompleting the wells upward. A vertical CO2-miscible flood was implemented in mid-1983 to improve recovery in the upper part of the reservoir, which was not completely waterflooded, and to mobilize oil in the water-swept region. CO2 was initially injected into two crestal wells to move the oil vertically downward toward the wells located lower on the structure. After the start of the CO2 flood, sufficient water injection continued in the flank wells to maintain reservoir pressure slightly above the minimum miscibility pressure (MMP) of 1,800 psig.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
- Well Completion > Well Integrity > Zonal isolation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Summary Screening criteria are useful for cursory examination of many candidate reservoirs before expensive reservoir descriptions and economic evaluations are done. We have used our CO2 screening criteria to estimate the total quantity of CO2 that might be needed for the oil reservoirs of the world. If only depth and oil gravity are considered, it appears that about 80% of the world's reservoirs could qualify for some type of CO2 injection. Because the decisions on future EOR projects are based more on economics than on screening criteria, future oil prices are important. Therefore, we examined the impact of oil prices on EOR activities by comparing the actual EOR oil production to that predicted by earlier NatI. Petroleum Council (NPC) reports. Although the lower prices since 1986 have reduced the number of EOR projects, the actual incremental production has been very close to that predicted for U.S. $20/bbl in the 1984 NPC report. Incremental oil production from CO2 flooding continues to increase, and now actually exceeds the predictions made for U.S. $20 oil in the NPC report, even though oil prices have been at approximately that level for some time. Utilization of Screening Guides With the reservoir management practices of today, engineers consider the various IOR/EOR options much earlier in the productive life of a field. For many fields, the decision is not whether, but when, to inject something. Obviously, economics always play the major role in "go/no-go" decisions for expensive injection projects, but a cursory examination with the technical criteria (Tables 1 through 7) is helpful to rule out the less-likely candidates. The criteria are also useful for surveys of a large number of fields to determine whether specific gases or liquids could be used for oil recovery if an injectant was available at a low cost. This application of the CO2 screening criteria is described in the next section. Estimation of the Worldwide Quantity of CO 2 That Could Be Used for Oil Recovery. The miscible and immiscible screening criteria for CO2 flooding in Table 3 of this paper and in Table 3 of Ref. 1 were used to make a rough estimate of the total quantity of CO2 that would be needed to recover oil from qualified oil reservoirs throughout the world. The estimate was made for the IEA Greenhouse Gas R&D Program as part of their ongoing search for ways to store or dispose of very large amounts of CO2 in case that becomes necessary to avert global warming. The potential for either miscible or immiscible CO2 flooding for almost 1,000 oil fields was estimated by use of depth and oil-gravity data published in a recent survey. The percent of the fields in each country that met the criteria in Table 3 for either miscible or immiscible CO2 flooding was determined and combined with that country's oil reserves to estimate the incremental oil recovery and CO2 requirements. Assuming that one-half of the potential new miscible projects would be carried out as more-efficient enhanced secondary operations, an average recovery factor of 22% original oil in place (OOIP) was used, and 10% recovery was assumed for the immiscible projects. A CO2 utilization factor of 6 Mcf/incremental bbl was assumed for all estimates. This estimated oil recovery for each country was then totaled by region, and all the regions were totaled in Table 8 to provide the world totals. The basis for the assumed incremental oil recovery percentage and CO2 utilization factors and other details are given in Ref. 3. Economics was not a part of this initial hypothetical estimate. Although pure CO2 can be obtained from power-plant flue gases (which contain only 9 to 12% CO2), the costs of separation and compression are much higher than the cost of CO2 in the Permian Basin of the U.S. For this study, we assumed that pure, supercritical CO2 was available (presumably by pipeline from power plants) for each of the fields and/or regions of the world. Table 8 shows that about 67 billion tons of CO2 would be required to produce 206 billion bbl of additional oil. The country-by-country results and other details (including separate sections on the costs of CO2 flooding) are given in Ref. 3. Although not much better than an educated guess with many qualifying numbers, our estimate agrees well with other estimates of the quantity of CO2 that could be stored (or disposed of) in oil reservoirs. Although this is a very large amount of CO2, when the CO2 demand is spread over the several decades that would be required for the hypothetical CO2 flooding projects, it would reduce worldwide power-plant CO2 emissions into the atmosphere by only a few percent per year. Therefore, more open-ended CO2 disposal methods (such as the more-costly deep-ocean disposal) will probably be needed if the complex general circulation models of the atmosphere ever prove conclusively that global warming from excess CO2 is under way. However, from the viewpoint of overall net cost, one of the most efficient CO2 disposal/storage systems would be the combined injection of CO2 into oil reservoirs and into any aquifers in the same or nearby fields. By including aquifers, this potential for underground CO2 storage would be increased significantly, and the quantity sequestered could have a significant impact on reducing the atmospheric CO2 emissions from the world's power plants. Impact of Oil Prices on EOR Major new EOR projects will be started only if they appear profitable. This depends on the perception of future oil price. Therefore, the relationship between future oil prices and EOR was a major thrust of the two NPC reports. These extensive studies used as much laboratory and field information as possible to predict the EOR production in the future for different ranges of oil prices. Now, it is possible to compare the NPC predictions with actual oil production to date. These comparisons were made recently to see how oil prices might affect oil recovery from future CO2 projects. We have extended these graphical comparisons and reproduced them here as Figs. 1 through 3. In general, the figures confirm that EOR production increases when prices increase and EOR production declines when prices fall, but not to the extent predicted. There is a time lag before the effect is noted. Figs. 1 and 2 show that total EOR production did increase in the early 1980's when oil prices were high. This was in response to an increase in the number of projects during this period when prices of up to U.S. $50/bbl or more were predicted. Although the rate of increase slowed in 1986 when oil prices dropped precipitously, EOR production did not decline until 1994, after several years of low oil prices (i.e., less than U.S. $20/bbl).
- Europe (1.00)
- North America > United States > Texas (0.34)
- North America > United States > New Mexico (0.34)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- Health, Safety, Environment & Sustainability > Environment > Air emissions (1.00)
EOR Screening Criteria Revisited - Part 1: Introduction to Screening Criteria and Enhanced Recovery Field Projects
Taber, J.J. (New Mexico Petroleum Recovery Research Center) | Martin, F.D. (New Mexico Petroleum Recovery Research Center) | Seright, R.S. (New Mexico Petroleum Recovery Research Center)
Summary Screening criteria have been proposed for all enhanced oil recovery (EOR) methods. Data from EOR projects around the world have been examined and the optimum reservoir/oil characteristics for successful projects have been noted. The oil gravity ranges of the oils of current EOR methods have been compiled and the results are presented graphically. The proposed screening criteria are based on both field results and oil recovery mechanisms. The current state of the art for all methods is presented briefly, and relationships between them are described. Steamflooding is still the dominant EOR method. All chemical flooding has been declining, but polymers and gels are being used successfully for sweep improvement and water shutoff. Only CO2 flooding activity has increased continuously. Introduction Oil-production from EOR projects continues to supply an increasing percentage of the world's oil. About 3% of the worldwide production now comes from EOR. Even though EOR production in the U.S. appeared to peak in 1992, Fig. 1 shows that the EOR percentage of the U.S. production is larger than ever, because conventional oil production in the U.S. has continued to fall. Therefore, the importance of choosing the "best" recovery method becomes increasingly important to petroleum engineers. About 100 years ago, oil producers injected gas to restore pressure to their dying oil wells. Because air was cheaper than gas, air was often injected to increase production from the older fields. For many years, operators had the choice of air or gas, and sometimes they injected both into the same reservoir. Naturally, there were safety and other problems with air. However, not until about 1928 did natural gas become the injectant of choice for pressure maintenance. Water injection was legalized in Pennsylvania in 1921 (it was done secretly before that). The choice of injectants has widened considerably since those early days, but the petroleum engineer still must choose an injection fluid and an overall process to try to recover the maximum amount of oil from the reservoir while still making a profit. Screening criteria have evolved through the years to help the petroleum engineer make these decisions. Some of the early work in this field was done by Geffen before there was much field experience with most EOR methods. Many of his criteria have stood the test of time. Perhaps the best known, and most widely used, screening criteria appeared in the 1976 and 1984 Natl. Petroleum Council (NPC) reports. We comment in Ref. 16 on some of the predictions based on these criteria. Ref. 9 is one paper that we are "revisiting." Although we retain the format of some of the tables in Ref. 9, all have been revised. We are basing our criteria in this paper on the results of much more field and laboratory information that has become available. Additional information (especially on the use of gelled polymers for water shutoff) is given in Ref. 17, the original version of this paper. In recent years, computer technology has improved the application of screening criteria through the use of artificial intelligence techniques, but the value of these programs depends on the accuracy of the input data used. In this paper, we present screening criteria based on a combination of the reservoir and oil characteristics of successful projects plus our understanding of the optimum conditions needed for good oil displacement by the different EOR fluids. One goal is to provide realistic parameters that can be used in the newer computer-assisted tools for reservoir management. EOR/Improved Oil Recovery (IOR)/Advanced Secondary Recovery (ASR)/Reservoir Management. In the past few years, the term IOR has been used increasingly instead of the traditional EOR, or the more restrictive "tertiary recovery." Most petroleum engineers understand the meaning of all the words and phrases, but our technical communications are improved if we use the terms with their intended technical meanings. We certainly endorse the wider use of IOR, but we cling to the technical meanings of EOR and tertiary recovery. Successful enhanced recovery projects are being conducted as tertiary, secondary, and even enhanced primary operations. The terms should continue to be used with their evolved historic meanings. Tertiary should not be used as a synonym for EOR because some EOR methods work quite well as either secondary or tertiary projects (e.g., CO2 flooding), while others, such as steam- or polymer flooding, are most effective as enhanced secondary operations. To us, EOR simply means that something other than plain water or brine is being injected into the reservoir. We use the terms "enhanced secondary" or tertiary when necessary for clarity. Others may use the phrase ASR for EOR in the secondary mode. We are convinced that engineers should consider this improved (enhanced or advanced) secondary option much more often in the future. Classification of EOR Methods. Table 1 lists more than 20 EOR methods that experienced intensive laboratory and, in most cases, significant field testing. The methods use about 15 different substances (or specific mixtures) that must be purchased and injected into the reservoir, always at costs somewhat greater than for the injection of water. The economics of EOR are discussed more later, but experience shows that the best profits come only from those methods where several barrels of fluid (liquid or gas at reservoir pressure) can be injected per barrel of incremental oil produced. This limits the main methods to either water (including heated, as steam, or as a dilute chemical solution) or one of the inexpensive gases. For some methods (e.g., micellar/polymer) there have been some technical successes but relatively few economic successes. These methods are included in our screening criteria because they are still being studied and applied in the field. If oil prices rise significantly, there is hope that these methods might become more profitable. We provide screening criteria for the eight methods that are either the most important or still have some promise. These eight methods are shown in in Table 1, along with the number of the table in Ref. 16 for those methods that are examined in detail. These "current" EOR or IOR methods include the three gas (nitrogen, hydrocarbon, CO2), three water [micellar/polymer plus alkaline/surfactant/polymer (ASP); polymer flooding; gel treatments] and the three thermal/mechanical (combustion, steam, surface mining) methods. A convenient way to show these methods is to arrange them by oil gravity as shown in Fig. 2. This "at-a-glance" display also provides approximate oil gravity ranges for the field projects now under way. The size of the type in Fig. 2 is intended to show the relative importance of each of the EOR methods in terms of current incremental oil production. EOR/Improved Oil Recovery (IOR)/Advanced Secondary Recovery (ASR)/Reservoir Management. In the past few years, the term IOR has been used increasingly instead of the traditional EOR, or the more restrictive "tertiary recovery." Most petroleum engineers understand the meaning of all the words and phrases, but our technical communications are improved if we use the terms with their intended technical meanings. We certainly endorse the wider use of IOR, but we cling to the technical meanings of EOR and tertiary recovery. Successful enhanced recovery projects are being conducted as tertiary, secondary, and even enhanced primary operations. The terms should continue to be used with their evolved historic meanings. Tertiary should not be used as a synonym for EOR because some EOR methods work quite well as either secondary or tertiary projects (e.g., CO2 flooding), while others, such as steam- or polymer flooding, are most effective as enhanced secondary operations. To us, EOR simply means that something other than plain water or brine is being injected into the reservoir. We use the terms "enhanced secondary" or tertiary when necessary for clarity. Others may use the phrase ASR for EOR in the secondary mode. We are convinced that engineers should consider this improved (enhanced or advanced) secondary option much more often in the future. Classification of EOR Methods. Table 1 lists more than 20 EOR methods that experienced intensive laboratory and, in most cases, significant field testing. The methods use about 15 different substances (or specific mixtures) that must be purchased and injected into the reservoir, always at costs somewhat greater than for the injection of water. The economics of EOR are discussed more later, but experience shows that the best profits come only from those methods where several barrels of fluid (liquid or gas at reservoir pressure) can be injected per barrel of incremental oil produced. This limits the main methods to either water (including heated, as steam, or as a dilute chemical solution) or one of the inexpensive gases. For some methods (e.g., micellar/polymer) there have been some technical successes but relatively few economic successes. These methods are included in our screening criteria because they are still being studied and applied in the field. If oil prices rise significantly, there is hope that these methods might become more profitable. We provide screening criteria for the eight methods that are either the most important or still have some promise. These eight methods are shown in in Table 1, along with the number of the table in Ref. 16 for those methods that are examined in detail. These "current" EOR or IOR methods include the three gas (nitrogen, hydrocarbon, CO2), three water [micellar/polymer plus alkaline/surfactant/polymer (ASP); polymer flooding; gel treatments] and the three thermal/mechanical (combustion, steam, surface mining) methods. A convenient way to show these methods is to arrange them by oil gravity as shown in Fig. 2. This "at-a-glance" display also provides approximate oil gravity ranges for the field projects now under way. The size of the type in Fig. 2 is intended to show the relative importance of each of the EOR methods in terms of current incremental oil production.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.74)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (27 more...)
Summary Gasflooding in oil reservoirs leads to bypassing of the oil due to gravitational, viscous and/or heterogeneity effects. The bypassed oil can be recovered by the flowing solvent by pressure-driven, gravity-driven, dispersion/diffusion-driven and capillarity-driven crossflow/mass transfer. It is difficult to represent all of these mechanisms explicitly in large-scale simulations. They need to be quantified at the laboratory scale, scaled-up appropriately and represented in large-scale simulations as added empirical terms e.g., cross-flow terms in dual-porosity models. In this work, we have studied the effect of the orientation of the bypassed region and the enrichment of the solvent on the mass transfer. Laboratory-scale mass transfer and coreflood experiments were conducted. Numerical simulation was used to identify the role of the different mechanisms. Results indicate that the mass transfer is the least for the vertical orientation, intermediate for the inverted orientation and the highest for the horizontal orientation. The mass transfer increases with enrichment for all orientations. Liquid phase diffusion controls vertical orientation mass transfer for the fluids studied. Phase behavior determines the liquid phase saturation. Capillary pumping does not contribute to the mass transfer of oil because the interfacial tension decreases towards the flowing region. Gravity-driven flow contributes the most to the mass transfer in the horizontal and the inverted orientations. The gravity-driven flow, however, is impeded by the capillarity whose magnitude decreases with solvent enrichment. Oil recovery in the horizontal gasfloods is nonmonotonic with enrichment for this fluid system in an almost homogeneous Berea core. Multiphase flow in the near- miscible floods leads to less gravity override compared to the FCM floods. In the heterogeneous core studied, the heterogeneity is very strong and the capillary forces do not prevent bypassing. The capillary forces, in fact, reduce oil recovery by diminishing mass transfer from the bypassed regions. Introduction The bypassing of oil is common in gasflooding due to rock heterogeneity, gravity override and viscous fingering. The extent of bypassing depends on the solvent enrichment as well as the injection strategies such as WAG ratio. Recent laboratory corefloods have shown that near-miscible solvents can be as or more effective than the first contact miscible solvents because of lower bypassing and favorable microscopic displacement efficiency. A significant fraction of oil initially bypassed by a solvent can be recovered subsequently by crossflow/mass transfer from the bypassed regions to the flowing region. Since near-miscible solvents appear attractive for gasflooding, it is important to identify and quantify the mechanisms of mass transfer when the solvent is not first contact miscible. Many reservoirs are naturally fractured. Waterflooding has traditionally been considered for the fractured reservoirs if the reservoir is water-wet. During waterflooding, the water displaces the oil from the fractures first and then imbibes into the matrix blocks due to the capillarity, if water-wet. Large quantities of water is typically recycled for significant oil production. Gasflooding of fractured reservoir is getting consideration only recently. Hara and Christman found CO2 flooding to be an attractive option for a diatomite reservoir; diffusion was the main mechanism for oil recovery from the matrix blocks. Firoozabadi et al. found miscible gas injection to be efficient in a fractured reservoir; gravity drainage was the key mechanism of oil recovery. Beliveau and Payne found the oil recovery to be 27% of the oil in place in a tertiary CO2 flood in a fractured reservoir. If near-miscible solvent floods are considered for fractured reservoirs, one needs to quantify the mass transfer between the matrix blocks and the fractures.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- (3 more...)
Summary Recent advances in software and hardware technology have made possible the development of field-scale, fully compositional CO2 flood simulations capable of capturing areal variations in performance on an individual well basis. This paper first describes the general methodology developed, including key elements used to construct such large models, followed by the validation of this approach. Two modeling studies conducted on the Wasson Denver Unit are then presented to highlight several of the significant outcomes realized so far: high-grading the profitability of new CO2 projects, pinpointing best well candidates to return to production, identifying infill and horizontal drilling locations, and identifying and quantifying injectant losses. Introduction The Denver Unit is located in Yoakum and Gaines County, Texas. The on-going CO2 project in this Unit is one of the world's largest. Each day, more than 500 million SCF of CO2 are injected into, while 39,000 barrels of oil are produced from the 1500 wells within the 21,000-acre project area. Since mid 1984, incremental oil recovery attributable to this tertiary process has exceeded 53 million barrels. Well-planned field operations and careful surveillance have both contributed to the success of this project. As of January 1994, CO2 developments of the Oil Column, the historical producing interval of the San Andres formation. have been relatively complete; the largest untapped reserves within the Unit are the 650 million barrels of paleo residual oil accumulated below the Oil Column. To profitably operate the on-going floods and to continue expansions of new CO2 developments under current oil prices, a much greater engineering and surveillance effort than ever before is required. As part of this effort, field-scale simulations have been employed to provide well-specific forecasts - a key piece of information which can help uncover flood improvement opportunities and high-grade new CO2 projects. An equation-of-state, compositional simulator has been chosen in the study because it can provide more reliable predictions of CO2-oil phase behavior than a black-oil-type model. Recent advances in simulation technology have made this effort possible. A study by Hill et al. has indicated that the simulator employed in the present study can provide reasonable predictions of the production response of a CO2 pilot in the South Welch Unit. In this paper, basic building elements of the modeling methodology such as reservoir characterization, phase behavior, relative permeability, and the process of validating the models are described first. Subsequently, key results of two field-scale simulation studies are summarized to highlight the impact of simulations on the field performance. The first case illustrates how we utilized a "TZ model" to design and high-grade CO2 flood expansions to recover residual oil in the Transition Zone. The second case demonstrates the use of a "Battery 1 model" to improve the on-going CO2 developments.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (29 more...)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (2 more...)
Alkaline/Surfactant/Polymer Pilot Performance of the West Central Saertu, Daqing Oil Field
Shutang, Gao (Institute of Petroleum E&D, Daqing Oil Field) | Huabin, Li (Institute of Petroleum E&D, Daqing Oil Field) | Zhenyu, Yang (Institute of Petroleum E&D, Daqing Oil Field) | Pitts, M.J. (Surtek, Inc.) | Surkalo, Harry (Surtek, Inc.) | Wyatt, Kon (Surtek, Inc.)
Summary A tertiary pilot application of the Alkaline-Surfactant-Polymer (ASP) process was initiated in September, 1994 in West Center Area of Daqing Oil Field. The pilot pattern consists of 4 inverted five-spot, including 4 injectors and 9 producers, as well as 2 observation wells encompassing an area of 90,000 m2 and with a pore volume of 203,300 m3. The target layer is Saertu II1-3 sandstone with average porosity of 26% and permeability of 1.426 m2. The crude oil viscosity is 11.5 mPa.S at reservoir temperature and the connate water salinity is 6,800 mg/L. The current pilot performance shows a pronounced response from Alkaline-Surfactant-Polymer injection. The average pilot area oil production rate increased from 36.7 m3/d to 91.5 m3/d, while water cut decreased from 82.7% to 59.7%. For the central well Po5, which is surrounded by injection wells, the oil production rate increased from 3.7 m3/d to 27.1 m3/d while water cut decreased from 87.9% to 45.8%. The numerical simulation results forecast that the oil recovery will be increased by 18.1% OOIP. Introduction The Daqing oil field is the largest field in the Peoples Republic of China. The pilot site is located on the west limb of the Saertu anticline. The reservoir slopes gently from east to west with an average depth of 814 m. The target layer in the pilot area, the Saertu II1-3 sandstone formation was deposited in a flood plain distributary environment. The sandbody is mainly composed of highly meandering distributary sandstone. The sandstone reservoir distribution is wide and thick, with high permeability and high inter-formational heterogeneity. The connate water salinity is relatively low, and fresh water is available. The reservoir characteristics, fluid properties, waterflood performance, and the performance of polymer flood pilot tests, indicated that the Daqing field was an ideal candidate for the Alkaline-Surfactant-Polymer process. Other papers have reported on ASP performance of field projects in the United States, but this paper reports on ASP effect at an advanced stage of waterflooding in the Daqing ASP pilot. History The Daqing field was discovered in 1959. Generalized water injection began in June of 1960 and separate layer injection began in January of 1965. The field was developed in a line drive pattern with rows of injectors 2,400 meters apart and spacing between wells within a row of 500 meters. Between rows of injectors are 3 rows of producing wells evenly spaced at 600 meters between rows. The oil production has been maintained at more than 160,000 m3/d since 1979 by this infill drilling and development resulting in more than 10,000 wells. Artificial lift development began in January of 1981 continuing until December of 1989. Beginning in 1984 the reservoir characteristics were screened for the application of enhanced oil recovery techniques. Two polymer flood pilots were performed beginning in 1987 with watercuts decreasing an average of 16% and oil rates increasing three-fold. These results indicated that mobility control polymer flooding could significantly improve oil recovery. As a result of these pilots, on-site polymer manufacturing facilities were built capable of producing 50,000 tons of polyacrylamide polymer per year. This facility began initial production in September of 1995. The Alkaline-Surfactant-Polymer process was identified as a means to further increase recovery and utilize the polymer made on site. The pilot area was originally developed beginning in December of 1987 for one of the polymer flood pilots. However, the polymer flood produced from intervals about 100 m deeper than the Alkaline-Surfactant-Polymer pilot. Fig. 1 shows the pilot area located between the well Zhong 5-8 and - Zhong 5-10 in the west central area of Daqing Field.
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Enhanced Waterflooding Design With Dilute Surfactant Concentrations for North Sea Conditions
Michels, A.M. (Shell Research Rijswijk) | Djojosoeparto, R.S. (Shell Research Rijswijk) | Haas, H. (Shell Research Rijswijk) | Mattern, R.B. (Shell Research Rijswijk) | van der Weg, P.B. (Shell Research Rijswijk) | Schulte, W.M. (Shell Research Rijswijk)
Summary Efficient selection procedures for surfactants have been applied to design a low concentration surfactant flooding process for North Sea oil field application. Anionic surfactants of the propoxy-ethoxy glyceryl sulphonate type can be used at 0.1 wt% concentrations together with sacrificial agents and without a polymer drive. Currently estimated unit technical costs (@8%) for application in the North Sea oil fields range from 13 to 15 $/incremental barrel, without taking uncertainty factors into account. Including such factors will likely add another 5 $/bbl to the costs. Introduction North Sea oil fields form a very large target for dilute surfactant flooding (DSF), some tens of millions tons of oil. Most of these fields produce light, low viscosity oil from sandstone reservoirs at high temperatures. The high costs of classical surfactant flooding techniques have inhibited the implementation of this technique in general and in the harsh environment of the Northern North Sea in particular. As a consequence a few years ago the research into surfactant flooding was redirected in an attempt to reduce costs with an order of magnitude. Some main design constraints were defined up-front to steer research towards an economic application. These main constraints were the application in a late secondary in stead of tertiary mode, use of dilute concentrations, reduce adsorption by sacrificial agents, avoiding the need for a polymer drive and reduce the risk of emulsions in the surface facilities. Research has concentrated on a surfactant mixture for which extremely low interfacial tensions between surfactant solution and oil can be created at concentrations around 0.1 wt%. Application of these surfactants was aimed at using such a system in its II- phase environment, trying to avoid the formation of micro-emulsions in a reservoir. Micro-emulsions are generally the cause of large retention and mobility problems. In this paper the target field selection criteria, the chemical formulation for the surfactant system and the results of laboratory floods will be discussed, followed by an economic evaluation.
- Europe > United Kingdom > North Sea (1.00)
- Europe > Norway > North Sea (1.00)
- Europe > North Sea (1.00)
- (3 more...)
- Geology > Mineral (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.56)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/24a > Dunlin Field > Brent Group Formation (0.98)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/23a > Dunlin Field > Brent Group Formation (0.98)
- Europe > United Kingdom > North Sea > Northern North Sea > Brent Formation (0.98)
- (2 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
SACROC Unit CO2 Flood: Multidisciplinary Team Improves Reservoir Management and Decreases Operating Costs
Hawkins, J.T. (Pennzoil E&P Co. ) | Benvegnu, A.J. (Pennzoil E&P Co. ) | Wingate, T.P. (Pennzoil E&P Co. ) | McKamie, J.D. (Pennzoil E&P Co. ) | Pickard, C.D. (Pennzoil E&P Co. ) | Altum, J.T. (Pennzoil E&P Co. )
Summary In 1992, the economic viability of the SACROC Unit was somewhat uncertain. At that time, a multidisciplinary team was formed to improve operational efficiencies and reservoir performance. Better understanding of reservoir geology from detailed biostratigraphic analysis provided the framework to make effective changes. This paper discusses operational efficiency and reservoir exploitation projects implemented by the team. Introduction The SACROC Unit of the Kelly-Snyder field is located in the Midland basin. The Midland basin is the easternmost of the Permian Basins of west Texas. This field is the largest of the many prolific, Late Pennsylvanian age carbonate buildups that comprise the Horseshoe Atoll. The field, discovered in 1948, encompasses 50,000 acres and contained an estimated original oil in place of 2.8 billion bbl. Waterflooding operations began in 1954 and CO2 flooding began in 1972. Cumulative recovery has been more than 1.2 billion bbl. The field contains approximately 1,600 wells with about 400 active producers and 240 active injectors. Recent changes implemented by the team have significantly improved operational efficiency at the unit. In addition, recent geologic investigations have finally begun to unravel the complex stratigraphy of the reservoir. Previous publications have documented the discovery of the Kelly-Snyder field, formation of the unit, completion of geologic and reservoir studies, and implementation of water- and CO2-flood projects at SACROC. Pennzoil acquired an interest in the field and became SACROC Unit operator beginning in late 1992. Shortly thereafter, a multidisciplinary team of reservoir engineers, geologists, production engineers, a facility engineer, and field operation personnel was formed and challenged with revitalizing the unit. Geologic Overview The SACROC Unit is situated on a prominent geologic feature named the Horseshoe Atoll (Fig. 1). The Horseshoe Atoll is a Middle Pennsylvanian through Early Permian age, isolated carbonate platform. During the Early Pennsylvanian, the Horseshoe Atoll was a broad platform, nearly circular in shape. However, beginning in the Late Pennsylvanian, the Midland basin began to subside rapidly. Subsequent tilting of the platform and drowning of the interior of the Horseshoe Atoll resulted in its characteristic arcuate or horseshoe shape. The SACROC Unit reservoir is a north-south trending carbonate buildup with a slight dogleg to the west (Fig. 2). The northern half of the unit is structurally highest, dips steeply to the west and east, and contains the thickest portion of the reservoir. To the south, the reservoir dips steeply, then flattens out to a broad, relatively flat platform. Along the eastern flank of the platform there is a trend of areally restricted "patch reefs." Overlying the entire structure is a thick sequence of dark black, organic-rich basinal shale. This thick sequence of shale forms both the seal and the source for the hydrocarbons trapped in this reservoir. On discovery in 1948, the reservoir was originally described as a thick carbonate reef. At the time, distribution of depositional facies and attendant porosity trends in complex carbonate reservoirs were poorly understood. Consequently, the original development of the field did not account for the complex stratigraphic nature of the reservoir. Also, initial rates from the primary zones were so high it was not necessary to maximize recovery from lower-porosity and -permeability zones. Finally, during the initial development phase, there were 81 separate operators, with as many as 250 rigs operating simultaneously. All these factors led the initial operators to either bypass or not effectively produce a considerable amount of pay in the SACROC Unit reservoir. Initially, only a few wells in the field were drilled to the oil/water contact (OWC). Those wells, drilled in the south, rarely penetrated more than 100 ft of the reservoir. During the early 1950's, most wells in the unit were deepened to -4,500 ft. On the basis of drillstem tests and production data, it was determined that the first occurrence of water was approximately -4,500 ft subsea. After deepening the wells, the operators began to suspect that there might be an extensive stratigraphic component to the reservoir. Throughout the reservoir, there are a few dense, tight streaks and thin shale zones. These tight zones were thought to be discontinuous, with the entire reservoir in pressure communication. Later, wells deepened to -4,500 ft found bottomhole pressures (BHP's) much higher than those in the shallower zones. This data indicated vertical isolation of the deeper zones from the shallower zones. Thus, the tight streaks in the reservoir were probably continuous across the field, with fluid flow being essentially horizontal. Even with this information, the reservoir continued to be described as a massive reef buildup by the original operators. Unit geologic studies in the late 1960's and early 1970's improved the reservoir description. These unpublished studies (done by Standard Oil of Texas/Chevron) indicate that numerous stacked, shoaling-upward cycles make up the reservoir. Laterally, the facies within the cycles were found to change abruptly. On the basis of this work and electric log correlations, the operators attempted to subdivide the reservoir into five major zones. Because deposition of the Horseshoe Atoll occurred in the middle of a relatively sediment-starved basin, no widespread shale markers were deposited. This, coupled with rapid lateral shifting of the depositional facies, made unitwide correlations unreliable. The lack of reliable markers to constrain correlations made it difficult to exploit this stratigraphically complex reservoir properly.
- Phanerozoic > Paleozoic > Carboniferous > Pennsylvanian > Upper Pennsylvanian > Kasimovian (0.54)
- Phanerozoic > Paleozoic > Carboniferous > Pennsylvanian > Upper Pennsylvanian > Gzhelian (0.54)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Reef Environment (0.88)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.86)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.85)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (29 more...)