Barrel Of Incremental Oil Research Articles

Evaluation of the Oil Recovery Potential and Cost Implication Analysis of Alternative ASP Formulations for Sandstone and Carbonate Reservoirs.

This study explores alternative chemical agents to enhance oil recovery in sandstone and carbonate reservoirs, aiming to address limitations in alkali-surfactant-polymer (ASP) flooding. Existing ASP methods face technical and environmental challenges, prompting research into alternative chemical agents. However, there are limited field deployments of these alternative chemical agents due to high costs, and ternary combinations of these agents remain unexplored. The study investigates a combination of organic alkali, amino acid-based surfactant/surface-active ionic liquid, and biopolymer. Comparative analysis with conventional ASP formulations reveals promising results. Organic alkali and biopolymer combination mitigates the adverse effects of inorganic alkalis on partially hydrolyzed polyacrylamide, enhancing the oil recovery potential. A unit technical cost (UTC) calculation showed that despite higher chemical costs per incremental barrel of oil, the alternative ASP formulations demonstrate comparable costs due to reduced facility cost. Cost-effectiveness will improve with incorporation of factors such as environmental friendliness and reduced preflush requirements. Mass production of these agents could further enhance the economic feasibility. Therefore, this study reveals that careful cost-benefit analysis, the development of low-concentration formulations, and mass production of these chemical agents could facilitate the implementation of these alternatives, ensuring compliance with environmental regulations and enabling ASP flooding in challenging reservoir conditions.

A novel foam process with CO2 dissolved surfactant for improved sweep efficiency in EVGSAU field

A successful CO2-foam gas conformance enhancement technology pilot has operated at the East Vacuum Grayburg San Andres Unit (EVGSAU) since Jan 2018 by ConocoPhillips in cooperation with Dow. In early 2020, the scope of the pilot was expanded from one pattern to three patterns. The expansion phase was implemented to evaluate scalability of this technology to patterns with diverse conformance issues and productivity inefficiencies. Severe vertical and areal conformance issues were initially identified in these patterns, resulting in early gas breakthroughs and poor oil sweep efficiencies. Due to economic success of the first phase, the same surfactant with high foaming tendencies, high gas solubility, and low adsorption characteristics was implemented in the new patterns.The first phase of foam implementation on an inverted pattern showed a complete elimination of out-of-zone injection, redistribution of CO2 into previously un-swept flow intervals, and oil production uplift.In contrast to this first pattern, the gas injectivity was reduced by 20–50% after only two foam cycles in the new patterns. Based on injection profile logs (IPL), no out-of-zone injection was identified before the surfactant injection for the two new patterns, which can be the reason for such rapid injectivity responses. Similar to the first pattern, deep conformance corrections were confirmed as gas was redirected from highly connected producers to other producers within the new patterns. A lower surfactant dosage was applied to one of the new patterns to optimize chemical consumption, while sustaining the performance. The surfactant concentration was also reduced in the first pattern to study the effect of a lower dosage on a known performing pattern. During the foam implementation, the gas to water ratio (GWR) at the pattern injectors was increased to maintain the patterns at the baseline total fluid throughput. This adjustment resulted in more than a 50% reduction in water consumption and a 17% improvement in gas utilization. Overall, a sustainable increase in oil production rate (∼35% over the baseline for the last two years) was achieved in the three foam patterns. This robust solution of gas conformance enhancement required ∼2 lbs. of foaming material per barrel of incremental oil produced, which confirms economic success and commercial viability of the foam technology for a full field-scale implementation.The application of this foam technology has potential to extend the life of a mature asset like EVGSAU by arresting the historical decline in the oil production rate. Reduction in energy and water consumption per barrel of oil produced make the CO2-EOR process more sustainable and strengthen its potential in carbon capture, utilization and sequestration (CCUS) application.

An Emerging CO2 Storage Option: CO2 Storage and By-Product Oil Recovery from Shale Oil Formations

Recent studies, sponsored by the United States Energy Association (USEA) and prepared by Advanced Resources International, have identified an emerging CO2 storage option – injecting and storing CO2 in shale oil formations. Because this CO2 storage option also provides by-product oil recovery, it offers a source of revenues and thus a potential “business case” for pursuing CO2 capture and storage. Shale oil (also called tight oil) has become the dominant source of U.S. oil production, increasing from less than 1 million barrels per day (MMB/D) a decade ago to about 8 MMB/D at the end of 2019. In addition, large shale oil basins and resources exist in many parts of the world, including Argentina, Australia, Canada, China, North and South Africa, and other settings, as evaluated by our company for the U.S. Energy Information Administration. (World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States, April 2011) Because of ultra-low permeability, oil recovery efficiency from shale oil formations using primary (pressure depletion) practices is low, on the order of 5 to 10% of the original oil in-place (OOIP). This leaves behind a large resource target for application of more advanced shale oil recovery technologies. Use of advanced recovery practices involving the injection of CO2 into shale oil formations (Shale EOR) provides one such technology and thus an additional pathway for economically viable storage of CO2. While a series of CO2 injection pilots are underway in U.S. shale oil basins, industry has held the results of these pilots “close to the vest.” To overcome this lack of information, the USEA sponsored a series of studies, involving the use of geologic characterization and reservoir engineering, to examine the potential of Shale EOR in four major U.S. shale oil basins - the Bakken Shale, the Eagle Ford Shale, and the Wolfcamp Shale in the Midland and Delaware Basins of the Permian Basin. This work showed that cyclic injection of CO2 can lead to additional recovery of oil from these shale oil formations while trapping and storing significant volumes of CO2. The study involved building a geologic model for a representative portion of each shale oil formation, history matching reservoir properties with well completion practices against actual well performance, and using a compositional reservoir simulator (GEM) to calculate oil recovery and CO2 storage from Shale EOR. Shale reservoir characterization and modeling for a “type area” of the Wolfcamp Shale in the Midland Basin illustrates the methodology and results of the Shale EOR study. With 12 cycles of CO2 injection, soak and production (over 8.5 years), Shale EOR stored 102,000 metric tons of CO2 in a representative 180-acre well pattern of the Wolfcamp Shale, while producing 223,000 barrels of shale oil. The 223,000 barrels of incremental oil, in addition to 355,000 barrels from primary oil recovery, provided an uplift of 63% in oil recovery. Using an additional CO2 injection cycle followed by well shut-in, Shale EOR stored 155,000 metric tons of CO2 in this 180-acre Midland Basin’s Wolfcamp Shale “type pattern”, equal to 0.7 metric tons of CO2 stored for every barrel of incremental shale oil produced. Similar evaluations of cyclic CO2 injection in other shale basins also showed that with Shale EOR more CO2 could be stored than the CO2 content in the oil produced. The Bakken Shale had a CO2 stored to oil produced ratio of 0.62 metric tons per barrel, the Eagle Ford Shale had a ratio of 0.39, and the Wolfcamp Shale of the Delaware Basin had a ratio of 0.69. As such, given that the combusted portion of a barrel of oil creates 0.38 metric tons of CO2, Shale EOR enables more CO2 to be stored than the CO2 content in a barrel of oil when combusted. (Approximately 12% of an oil barrel is used for petrochemicals and other non-combustion sources.) The study noted that special geologic conditions and development practices are important for optimum application of the cyclic CO2 injection and storage process. Future pathways being evaluated for this emerging CO2 storage option and a potential new “business case” for CCUS include: (1) examining continuous, rather than cyclic, injection of CO2 and (2) using conformance and other CO2 storage enhancing technologies. These technologies would appreciably increase the volumes of CO2 able to be stored as well as improve the oil recovery efficiency of Shale EOR.

CO2-EOR+ in Australia: achieving low-emissions oil and unlocking residual oil resources

The petroleum industry, through the production and consumption of oil and gas, contributes to global greenhouse gas emissions. However, the industry’s leadership and experience in underground injection and storage of CO2, especially through CO2 enhanced oil recovery (CO2-EOR), which has been proposed as a possible solution to reducing atmospheric CO2 levels, has not been well acknowledged. Unlike traditional CO2-EOR, which tends to be a net carbon emitter due to the use of predominantly natural CO2, rather than anthropogenic, CO2-EOR+ focuses on storing a larger volume of CO2. Thus CO2-EOR+ not only provides a potential solution to dispose of anthropogenic emissions but at the same time reduces reliance on imported oil through increased domestic production. Increased industry interest and energy policy strategies directed at reducing and/or removing emissions from industry processes reflect the growing social and economic impetus to improve operation practices and the petroleum industry’s reputation. Residual oil zones (ROZs) below identified oil–water contacts provide an excellent target for the application of CO2-EOR+. They offer a producible residual oil resource accessible through CO2-EOR, as well as a large pore volume for CO2 storage, with efforts focused on converting ROZs into resources and reserves. Existing fields in the Surat and Cooper-Eromanga Basins are already well placed to utilise anthropogenic CO2 sources to achieve conventional CO2-EOR metrics. The ROZs in these basins will hopefully allow potential EOR projects to increase the CO2 volumes stored, per incremental barrel of oil, well past traditional levels (0.2–0.3 tCO2/bbl), and in doing so, potentially achieve net negative-emission oil.

Multiobjective design and optimization of polymer flood performance

The design and optimization of polymer flood projects have traditionally focused on increasing oil production only. For economic viability, the optimization strategy should maximize oil production while minimizing polymer usage. However, these two objectives can be conflicting. The challenge is how to optimize polymer flood design considering the trade-off between these conflicting objectives.In this work, we utilize the concept of Pareto optimality to generate a set of Pareto optimal solutions that represent a trade-off relation between the conflicting objectives viz. polymer utility factor and incremental oil gain. The Pareto optimal solutions can be searched by a non-domination based genetic algorithm (NSGA-II). The algorithm evaluates fitness by a dominance relationship instead of fitness measures as in the ordinary single-objective genetic algorithm. The dominance concept defines levels of optimality by assigning several ranks to each population. The algorithm iteratively minimizes ranks until all members of the population become rank one which implies that the Pareto optimality condition is reached.The application of our proposed method is demonstrated by a 2D synthetic example and a 3D field-scale application. The Pareto-based approach is implemented to simultaneously optimize two objectives: (1) polymer utility factor (UF) which is the amount of polymer required per barrel of incremental oil and (2) cumulative incremental oil production (Np). The results demonstrate that beyond the optimal design, relatively minor increase in oil production requires significantly more polymer injection and the polymer UF is increased substantially.To optimize both oil production and polymer utility, the Pareto optimal solutions provide the best compromise that enables maximizing oil production while maintaining the efficiency of polymer usage.

How green is my oil? A detailed look at greenhouse gas accounting for CO2-enhanced oil recovery (CO2-EOR) sites

This study presents the results of a detailed life cycle analysis of greenhouse gas (GHG) emissions associated with carbon dioxide-enhanced oil recovery (CO2-EOR) where the CO2 is sourced from a coal-fired power plant. This work builds upon previous investigations and integrates new information to provide more plausible ranges for CO2 storage in the reservoir during CO2-EOR. The system model includes three segments: upstream, gate-to-gate, and downstream processes. Our base case model using Ryan–Holmes gas separation technology for the CO2-EOR site determined the emissions from upstream, gate-to-gate, and downstream processes to be 117, 98, and 470kg CO2e/bbl (CO2 equivalents per barrel of incremental oil produced), respectively, for total emissions of 685kg CO2e/bbl. However, these emissions are offset by CO2 storage in the reservoir and the resulting displacement credit of U.S. grid electricity, which results in a net life cycle emission factor of 438kg CO2e/bbl. Therefore, CO2-EOR produces oil with a lower emission factor than conventional oil (∼500kg CO2e/bbl). Optimization scenarios are presented that define a performance envelope based on the CO2 capture rate and net CO2 utilization and suggest that lower emission factors below 300kg CO2e/bbl are achievable. Based on these results, CO2-EOR where the CO2 is sourced from a coal-fired power plant provides one potential means for addressing the energy demand–climate change conundrum, by simultaneously producing electricity and oil to meet growing energy demand and reducing GHG emissions to abate global warming.

E&P Notes (November 2015)

E&P Notes Digitizing Core Scans Brings Old Methods into 21st Century Trent Jacobs, JPT Senior Technology Writer In the search for oil and gas, one of the first investments that companies make is in the analysis of core samples. Pulled directly from the reservoir rock, core samples provide critical data used to determine how an exploration program should move forward, or if at all. However, compared with the high-tech methods found in so many other arenas of the oil and gas industry, the conventional methods used to examine core samples seem quite antiquated. Petroleum geologists are usually given the first look at the samples to measure key rock features such as natural fractures and to estimate the size of the rock grains. And among the tools most often used to make these measurements and provide a detailed description of the core are a magnifying hand lens, a ruler, and a pad of paper. As tried and true as these analog technologies have proven to be for much of the industry’s history, there is an ongoing transition to bring the process of core description into the digital age. Treating Damaged Subsea Lines With a Light Electrical Touch Stephen Rassenfoss, JPT Emerging Technology Senior Editor As subsea electric lines age, they are prone to cracks that allow seawater in, reducing their effectiveness, and if the leaks are bad enough, they can shut down operations. A British subsea engineering and equipment company is selling a novel repair option that can be installed without ever going into the water. Viper Subsea’s solution comes in the form of a box sending out specially programmed electrical signals. It has installed units on 17 umbilicals and subsea cables and it worked in all but two cases, said Max Nodder, business development director and cofounder of Viper, during a presentation at SPE Offshore Europe. For anyone whose mental image of insulation is a hard plastic shell isolating wires from the elements, Viper’s method may seem farfetched. But the conventional alternative is not easy to accept either, given the time and money required to replace subsea lines that can run for miles. Three Offshore Blocks Awarded in Mexico’s Second Auction Trent Jacobs, JPT Senior Technology Writer Mexico’s second oil and gas lease auction has been deemed a success after three out of five shallow-water blocks were awarded in September. The awarded areas contain an estimated 236 million bbl of oil and 190 Bcf of gas. The government expects the auction to result in a USD 3 billion investment and up to 90,000 B/D in production by the start of the next decade. The auction’s outcome was warmly welcomed by Mexico’s National Hydrocarbons Commission, known by its Spanish-language acronym CNH, which has been working for more than a year to organize the historic opening of the country’s exploration and production sector. “We believe that our mandate of obtaining the best conditions for the Mexican state was achieved,” said Edgar Rangel-German, a CNH commissioner. Halliburton Reveals Refracturing Strategy Trent Jacobs, JPT Senior Technology Writer Although refracturing is a topic that has gained a lot of interest, many shale producers have been sitting on the sidelines because early results did not justify the spending. Halliburton has now joined other service companies in announcing that its results prove the technology is ready for prime time. The company’s encouraging numbers show that on average, it is seeing ultimate recovery increases of 80% and a two-thirds reduction in the cost per incremental barrel of oil from a refractured well compared with each barrel from a new well. Priyesh Ranjan, a senior manager of global business development at Halliburton, presented the details of the company’s new Activate Refracturing Service in September. Speaking before an audience of oil and gas company representatives in Houston, Ranjan tried to dispel the notion that the majority of refracturing candidates are primarily vintage wells because of the improvements made in completion technologies and fracture designs in recent years. Middle East NOCs To Boost Collaboration in Joint Projects Abdelghani Henni, JPT Middle East Editor National oil companies (NOCs) in the Middle East plan to boost their collaboration efforts in technology applications through a global industry trade organization’s initiative. For the first time, Gulf Cooperation Council (GCC) members of the Industry Technology Facilitator (ITF) held a summit in Abu Dhabi. They agreed to take forward three technology challenges with the aim of defining a call for proposals for collaborative joint industry projects (JIPs) later this year. The summit was attended by representatives from the Abu Dhabi National Oil Company, Kuwait Oil Company, and Petroleum Development Oman, three of the six GCC members.

Technology Update: New Microbial Method Shows Promise in EOR

Technology Update Tertiary oil recovery technologies can extend the economic life of maturing waterflooded reservoirs. This article describes the results from a biologically based enhanced oil recovery (EOR) technology that has improved waterflood efficiency by increasing oil production and decreasing the decline rates, thereby significantly increasing the recovery factor. Traditional tertiary recovery processes such as thermal methods, CO2 flooding, and chemical flooding require significant changes to field infrastructure and usually involve relatively high operating expenditures of up to USD 50 per incremental barrel of oil produced. Called Activated Environment for the Recovery of Oil (AERO), the technology used in this project represents a breakthrough in biologically based EOR by using a continuous injection of inorganic nutrients to stimulate indigenous microbes. The use of continuous injection (water and nutrients), which differentiates AERO from most previously attempted microbial EOR methods, prevents production disruptions and makes it easier to accurately measure, assess, and document the production benefits. The key advantages of this method are Decreased decline rates, enabling significant reserve gains Increased oil production Low capital expenditures Low operating costs Rapid response Biological EOR uses inorganic nutrients to activate indigenous microbes, those native to the field. Because no organic carbon is introduced, the microbial growth is restricted to the interface between the injection water and the oil, the carbon source for growing the microbes. The use of indigenous microbes is advantageous because they are perfectly suited to the local conditions and, unlike externally originated organisms, are neither costly to produce nor prone to rapid death in the reservoir and are thus in need of replacement. In addition, the concentrations of the nutrients required are relatively low, a major reason for the feasibility of continuous injection and stimulation. The technology is among the most inexpensive tertiary recovery methods available and requires only minimal changes to waterflood facilities for deployment. It can likewise be used with relatively minor modifications in fields without an operating waterflood, such as fields with a natural waterdrive or very mature fields where waterflooding has ceased. The biological EOR technology is producing a growing body of positive results, such as the following example from Canada.

Polymer-Flooding-Pilot Learning Curve: Five-Plus Years' Experience To Reduce Cost per Incremental Barrel of Oil

Summary This paper deals with the learning curve of a five-plus-year polymer-flooding pilot conducted in a mature waterflood that includes, for example, several works related to injector and producer wells and reservoir management. The scope of this paper is to describe the learning curve during the last 5 years rather than the reservoir response of the polymer-flooding technique; focus is on the aspects related to reduce cost per incremental barrel of oil for a possible extension to other waterflooded areas of the field. Diadema oil field is in the San Jorge Gulf basin in the southern portion of Argentina. The field is operated by CAPSA, an Argentinean oil-producer company; it has 480 producer and 270 injector wells (interwell spacing is 250 m on average). The company has developed waterflooding over more than 18 years (today, this technique represents 82% of oil production in the field) and produces approximately 1600 m3/d of oil and 40 000 m3/d of gross production (96% water cut) with 38 400 m3/d of water injection. The reservoir that is polymer-flooded is characterized by high permeability (average of 500 md), high heterogeneity (10 to 5,000 md), high porosity (30%), very stratified sandstone layers (4 to 12 m of net thickness) with poor lateral continuity (fluvial origin), and 20 °API oil (100 cp at reservoir conditions). Diadema's polymer-flooding pilot started in October 2007 on five water injectors (it includes 13 injectors today) with an injected rate of 1000 m3/d (today, 2000 m3/d). Polymer solution is made with produced water (15,000 ppm brine) and 1,500 ppm of hydrolyzed polyacrylamide polymer reaching 15- to 20-cp fluid-injection viscosity. Oil-production rate from the original “central” producers (wells that are aided with 100% of polymer injection) has increased 100% at the same time as average reduction in water cut is approximately 15%. The main aspects presented in this work are depth profile modification with crosslinked gel injected along with polymer, use of “curlers” to regulate injection in multiple wells with one injection pump without shearing the polymer, and an improved technology on producer wells with progressing-cavity pumps to decrease shut-in time and number of pump failures. The plan for the future is to extend this project to other areas with the acquired knowledge and to improve different aspects, such as water quality and optimization of polymer plant operation. These improvements will allow the company to reduce operating costs per incremental barrel of oil.

Polymer-Flooding Pilot Finds Success in Previously Waterflooded Reservoir

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 166255, ’Polymer-Flooding-Pilot Learning Curve: 5+ Years' Experience To Reduce Cost Per Incremental Barrel of Oil,’ by J. Buciak, SPE, G. Fondevila Sancet, and L. Del Pozo, Grupo CAPSA, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed. A successful pilot test of polymer flooding was conducted in the San Jorge Gulf basin, a mature waterflood with the presence of heterogeneous reservoirs and viscous oil under reservoir conditions. During the past 5 years, 3,200 tons of hydrolyzed polyacrylamide polymer was injected at concentrations of 1,500 ppm. The polymer flooding resulted in an increase in oil production to 100% and a decrease in water production to 50% in original central wells. Introduction The Diadema oil field is in the San Jorge Gulf basin in southern Argentina. The field has 480 producer wells and 270 injector wells. The reservoir being polymer flooded is characterized by high permeability (an average of 500 md), high heterogeneity (10–5,000 md), high porosity (30%), very stratified sandstone layers (4–12 m of net thickness) with poor lateral continuity (fluvial origin), and 20 °API oil (100 cp under reservoir conditions).

Recent Developments and Remaining Challenges of Enhanced Oil Recovery

R&D Grand Challenges - This is the second in a series of articles on the great challenges facing the oil and gas industry as outlined by the SPE R&D Committee. The R&D challenges comprise broad upstream business needs: increasing recovery factors, in-situ molecular manipulation, carbon capture and sequestration, produced water management, higher resolution subsurface imaging of hydrocarbons, and the environment. The articles in this series are examining each of these challenges in depth. The R&D Grand Challenges Series, comprising articles published in JPT during 2011 and 2012, is available as a collection on OnePetro (SPE-163061-JPT). The world is changing. Some look back and some look forward. Some look at the challenges of ramping up enhanced oil recovery (EOR) in the past and some look at the opportunities for doing so now. This article will provide a broad view of recent developments and the remaining challenges for readers who are not EOR specialists. There has been a renaissance in chemical EOR during the past few years because of major advances in the technology and high oil prices. Thermal and miscible gas methods are much more mature with the exception of processes such as co-injection of gases and surfactants for mobility control. The synergy between the EOR processes and improved reservoir characterization and formation evaluation, reservoir modeling and simulation, reservoir management, well technology, production methods, and facilities is significant and not as widely recognized as it should be. Polymer flooding is the simplest and most widely used chemical EOR process. Polymer flooding has been used commercially since the 1960s; more oil is produced by polymer flooding than all of the other chemical EOR processes combined. Adding polymer to the water increases its viscosity. The benefit of polymer flooding increases as the oil viscosity and/or the reservoir heterogeneity increases. Polyacrylamide copolymers or hydrolyzed polyacrylamide (HPAM) polymers are by far the most widely used polymer for EOR. Much higher molecular weight HPAM is now available than when it was first used in the 1960s and 1970s. The quality of commercial HPAM polymer has also improved dramatically and the price relative to crude oil has decreased. In the early 1970s, oil sold for about USD 3/bbl and HPAM polymer for about USD 1.50/lb. Now oil is about USD 100/bbl and HPAM stays about the same price. About 1 to 2 lbs of polymer are needed to produce an incremental barrel of oil, which means the polymer cost is about USD 1.50/bbl to USD 3/bbl. This helps explain why the number of polymer floods is increasing exponentially and about 1 billion lbs of polymer will be used for EOR this year. Most early polymer floods were done using very small amounts of polymer (i.e., low polymer concentrations and small pore volumes of polymer solution), but now we know polymer floods perform much better at large polymer concentration.

Successful Field Pilot of In-Depth Colloidal Dispersion Gel (CDG) Technology in Daqing Oil Field

Summary The first large-scale colloidal dispersion gel (CDG) pilot test was conducted in the largest oil field in China, Daqing oil field. The project was initiated in May 1999, and injection of chemical slugs was completed in May 2003. This paper provides detailed descriptions of the gel-system characterization, chemical-slug optimization, project execution, performance analysis, injection facility design, and economics. The improvements of permeability variation and sweep efficiency were demonstrated by lower water cut, higher oil rate, improved injection profiles, and the increase of the total dissolved solids (TDS) in production wells. The ultimate incremental oil recovery (defined as the amount of oil recovered above the projected waterflood recovery at 98% water cut) in the pilot area would be approximately 15% of the original oil in place (OOIP). The economic analysis showed that the chemical costs were approximately U.S. $2.72 per barrel of incremental oil recovered. Results are presented in 15 tables and 8 figures.

Electrical-heating-assisted recovery for heavy oil

Warming heavy oil (940–1000 kg/m 3, 10°–20° API) reduces its viscosity substantially; however, conventional thermal recovery by steam injection is not applicable to a number of heavy-oil reservoirs. This paper explores localized electric resistance heating provided by mineral-insulated cable and a novel heater–well arrangement. Two-dimensional (2-D) and heterogeneous three-dimensional (3-D) reservoir simulation models employing single- and dual-lateral completion horizontal wells illustrate that an electric resistance heating element with a modest power output enhances recovery several fold. Important parameters for improved recovery are (1) solution gas, (2) formation and fluid thermal conductivity that permits conductive heating, and (3) the ability to achieve relatively low bottom-hole pressure in production wells. Economic analysis suggests that the cost of electricity is about 1.25 USD per barrel of incremental oil.

Carbon dioxide production from coal-fired power plants for enhanced oil recovery: A feasibility study in Western Canada

In order to sustain the current production capacity of conventional oil in Western Canada, enhanced oil recovery (EOR) technologies must be increasingly applied. Among these, CO 2 flooding is a highly attractive alternative. A large amount of CO 2 is being produced by coal-fired power plants in this region. The CO 2 is currently discharged into the atmosphere and could be a major contributor to the greenhouse effect, which may lead to global warming. Thus, the concept of capturing CO 2 and utilizing it as a flooding agent in EOR processes is currently generating much interest among oil, utility and coal companies. We demonstrate how cogeneration concepts, together with process-optimization strategies, help to reduce the CO 2-production cost by utilizing low-pressure steam and waste heat from various sections of the power-generation process. Based on these concepts and strategies, results from this study show that the recovery cost of CO 2 from a coal-fired power plant may range between $0.50 and 2.00/mscf. If the cost is approximately $1.25/mscf, the production cost of a barrel of incremental oil would be less than $18. Therefore, even at today's modest oil prices, there is room for profit to be made operating a CO 2 flood with flue-gas-extracted CO 2. The technical and economical feasibility of the concepts are evaluated and the practical implications for the Saskatchewan resources are discussed.

New feasibility study of carbon dioxide production from coal-fired power plants for enhanced oil recovery: A Canadian perspective

The concept of capturing carbon dioxide from coal-fired power plants and utilizing it as a flooding agent for enhanced oil recovery (EOR) processes is currently drawing much interest from oil, utility and coal companies in Western Canada. Implementation of such a scheme would provide two important benefits: (i) the captured CO 2 could be marketed as a flooding agent which would generate revenues, and (ii) CO 2 emissions to the atmosphere would be reduced. Since CO 2 emissions are considered to be the main contributor to the possible serious environmental problem of global warming, the proposed scheme could become an important instrument to reduce such emissions at minimal incremental cost to the environment. This paper demonstrates how cogeneration concepts, together with process optimization strategies, help to reduce the CO 2 production cost by utilizing low-pressure steam and waste heat from various sections of the power generation process. Based on these concepts and strategies, results from this study show that the recovery cost of CO 2 from a coal-fired power plant can range between $0.50–2.00/mscf. If the cost is approximately $1.25/mscf, the production cost of a barrel of incremental oil would be less than $12. Therefore, even at today's modest oil prices, there is room for profit to be made operating a CO 2 flood with flue gas extracted CO 2. The technical and economical feasibility of the concepts are evaluated and the practical implications for the Canadian resources are discussed.

A Full Field Model Study of the East Velma West Block Sims Sand Unit Reservoir

Summary A full-field numerical model of the East Velma West Block Sims Sand Unit (EVWBSSU) reservoir was developed. The three-dimensional, four-component, heterogeneous, 3,200-cell model will aid in the evaluation, analysis, and operation of a CO2 flood now in progress. CO2 is being injected in a continuous mode in the updip portion of the steeply dipping reservoir, A specially portion of the steeply dipping reservoir, A specially constructed grid, detailed reservoir description, and multiple fluid property tables were used to account for the variation in the reservoir's structure, geology, and fluid properties. The present state of the reservoir was properties. The present state of the reservoir was determined after 33 years of production history were matched. Methods of production included primary depiction under gravity drainage, secondary production using gas injection for pressure maintenance, and waterflood. From the history-matched model, field performance predictions were made for continued waterflood and various operating scenarios under the present CO2 injection scheme. Results include the effect Of CO2 pipeline supply rate, allocation Of CO2 and water to injection wells, and uncertain parameters on reservoir performance. From these projections it was concluded that the amount of injected projections it was concluded that the amount of injected CO2 required to produce an incremental barrel of oil over waterflood was not strongly dependent on CO2 pipeline supply rate or allocation of injected fluids to pipeline supply rate or allocation of injected fluids to injection wells. This conclusion seems reasonable mechanistically because the miscible displacement was dominated by gravity, the areal variation in predicted updip oil saturation was not great, and the continuous injection coupled with high permeability updip caused uniform distribution of CO2. Introduction The EVWBSSU reservoir was studied using a four- component numerical reservoir model. The steeply dipping reservoir is located in Stephens County, OK, and was discovered and developed during 1949–50. Methods of production during the life of the field included primary depletion under gravity drainage (1949–62), secondary production using gas injection for pressure maintenance production using gas injection for pressure maintenance (1962–72), and waterflood (1972–82). Field recovery through all phases of production history was 32.3%. Currently, the field is being flooded with CO2 and water. A pipeline supply of CO2 from a fertilizer plant in Enid, OK, along with recycled CO2 and gas obtained from a field processing plant, is being injected continuously into seven updip injection wells. The field model was developed as a planning tool to aid in the evaluation, analysis, and operation of the CO2 flood. A history match of the field production data yielded an estimate of the present state of the reservoir:current fluid saturations by tracking gross fluid movement during the life of the reservoir andverification of the reservoir and fluid descriptions. The most important mechanisms to history match for realistic predictions were the gas/oil gravity drainage and waterflood oil-rate decline. The gravity-drainage calculation gives an estimate of the location and movement of the gas/oil contact (GOC) during the first 23 years of production. This information is important in the sweeping production. This information is important in the sweeping of residual oil with the updip CO2 injection scheme. The waterflood oil-rate decline yields a forecast of how the reservoir would decline under present operating conditions. One can then evaluate how much better performance is with CO2 injection. performance is with CO2 injection. From the results of the history match, simulations to analyze the current updip CO2 injection operations were performed. Deliverability Of CO2 from the Enid fertilizer performed. Deliverability Of CO2 from the Enid fertilizer plant has been up to two-thirds less than anticipated. The plant has been up to two-thirds less than anticipated. The model was used to predict the effect of lower CO2 pipeline supply rates on reservoir performance. Then pipeline supply rates on reservoir performance. Then cases were run to evaluate current operations. Finally, sensitivity studies were performed on uncertain model parameters. parameters. Model Development A complex and carefully constructed reservoir model was required because of EVWBSSU's steep and variable dip, variation of fluid properties, and heterogeneity. A special grid was constructed to account for the field's structural variation. Multiple tables were used for some fluid properties. A detailed geologic description was constructed properties. A detailed geologic description was constructed from core and log data. Incongruent field data were compiled into a form suitable for history matching. Grid Construction. Gridblocks were constructed by a method that accounts for both the variation in the field's dip and its thickness. In addition, if it is assumed that the reservoir was deposited in layers parallel to the bedding plane, the resulting grid orientation is such that the plane, the resulting grid orientation is such that the permeability tensor contains only diagonal elements. permeability tensor contains only diagonal elements. JPT P. 1429