Wang, Bingjie (CNOOC LTD.-TianJin Bohai Oilfield) | Xu, Changgui (CNOOC LTD.-TianJin Bohai Oilfield) | Wu, Kui (CNOOC LTD.-TianJin Bohai Oilfield) | Zhang, Rucai (CNOOC LTD.-TianJin Bohai Oilfield) | Deng, Jun (CNOOC LTD.-TianJin Bohai Oilfield) | Guo, Naichuan (CNOOC LTD.-TianJin Bohai Oilfield)
A new oil property identification parameter (Pw) is derived which represents the total hydrocarbon generation and pyrolysis hydrocarbon. Using continuous measurement data (Pw) and a series of samplebased attributes from 3D seismic, a strong linear trend is observed. This trend linear is used to calculate heavy oil property data in 3D volume. At the same time, we have got the relationship between reservoir physical and oil properties. Based on this, the core data and geochemical data are used to study the charging of crude oil.
Aldhaheri, Munqith (Missan Oil Company and University of Misan) | Wei, Mingzhen (Missouri University of Science and Technology) | Zhang, Na (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
As life-span extenders, bulk gels have been widely applied to rejuvenate oil production from uneconomic producers in mature oil fields by improving the sweep efficiency of improved-oil-recovery (IOR)/enhanced-oil-recovery (EOR) floods. This paper presents a comprehensive review of the responses of injection-well gel treatments implemented between 1985 and 2014. The survey includes 61 field projects compiled from SPE papers and US Department of Energy reports. Seven parameters related to the oil-production response were evaluated according to the reservoir lithology, formation type, and recovery process, using univariate analysis and stacked histograms. The interquartile-range (IQR) method was used to detect the underperforming and overperforming gel projects. Scatterplots were used to identify the effects of the injected-gel volume and the treatment timing on the treatment response. Pretreatment water cut, recovery factor, and flood life were used as indicators for the treatment timing.
Results indicated that gel treatments have very wide ranges of response for injection and production wells and for oil and water rates and profiles. When successfully applied, they, on average, respond after 3.5 months, increase the oil-production rate by 32%, and additionally recover 116,000 STBO per treatment, 15 STBO per gel barrel, or 10 STBO per polymer pound. We identified that gel treatments perform more efficiently in carbonate (CB) than in sandstone (SS) reservoirs and in naturally fractured (NF) formations than in other formation types. In addition, the incremental oil production considerably increases with the channeling strength and the injected-gel volume for all formation types, not just for the matrix-rock (MR) reservoirs. Moreover, gel treatments applied in NF formations have lower productivities in SS than in CB reservoirs using normalized performance parameters.
Declining trends were identified for all parameters of the oil-production response with the treatment-timing indicators. The sooner the gel treatment is applied, the faster the response, and the larger the incremental oil production and its rate. It is recommended to allow longer evaluation times for gel treatments applied in MR formations because their response times might extend to several months. Gel treatments will perform more efficiently if they are conducted at water cuts of less than 70%, flood lives of fewer than 20 years, or recovery factors of less than 35%. For different application environments, the present review provides reservoir engineers with updated ideas regarding the low, typical, and high performances of gel treatments when successfully applied, as well as how other treatment aspects affect performance.
Varshney, Mayank (Cairn Oil and Gas, Vedanta Limited) | Goyal, Aman (Cairn Oil and Gas, Vedanta Limited) | Goyal, Ishank (Cairn Oil and Gas, Vedanta Limited) | Jain, Akanksha (Cairn Oil and Gas, Vedanta Limited) | Pandey, Nimish (Cairn Oil and Gas, Vedanta Limited) | Parasher, Arunabh (Cairn Oil and Gas, Vedanta Limited) | Vermani, Sanjeev (Cairn Oil and Gas, Vedanta Limited) | Negi, Anil Singh (Baker Hughes, A GE Company) | Sharma, Vinit (Baker Hughes, A GE Company)
Waterflood is most commonly used secondary recovery mechanism in conventional sanstone reservoirs worldwide. Waterflooding assists in pressure maintenance and increases the field estimated ultimate recovery (EUR). Conformance in water injector wells plays an important role during waterflooding of a reservoir. Better conformance results in improved vertical sweep efficiency leading to higher recovery.
Continuous injection of fluids into the reservoir at higher rates may create channels for preferential flow. Zones of higher permeability, leading to higher injectivity in selective zones, can also exist because of various lithological conditions and rock structures comprising of naturally occurring fractures or fissures. For injection wells, the entry of fluids into a set of perforations is governed by the quality of the perforations and the permeability of the formation at that depth. Preferential flow of injected fluids into selective pay intervals results in diminished overall sweep efficiency. (J. Vasquez, et.al., 2008).
This paper discusses the use of thermally activated gels from polyacrylamides and metal chelates applied for selective reservoir matrix permeability reduction in an injector well. A low concentration, low viscosity delayed crosslinker gel system employing partially hydrolyzed polyacrylamide (PHPA) exhibiting 12-14% degree of hydrolysis level with chromium acetate as crosslinker offering delayed gelation time was used to selectively isolate one of the payzones.
A non-profile retrievable (NPR) plug was installed to isolate the target interval from the rest of the pay zones to enable selective treatment of the interval using coiled tubing (CT). The fluid was customized to minimize CT friction while ensuring that the rheological properties of the fluid in the reservoir would achieve the desired diversion and allow delayed gel crosslinking mechanism assuring avoiding of gel crosslinking in CT while pumping in progress. Denser brine relative to the delayed gel density was spotted above the NPR plug to avoid gel settling on the plug for easy retrieval of the plug post-treatment. Injectivity was measured and subsequently, the treatment was placed as per design while constantly monitoring the pressures so as to qualitatively determine the effectiveness of the treatment placement.
The treatment resulted in significant alteration in injectivity of the targeted zone. Post-treatment production logs confirmed an improvement in the injection conformance. Later, the zone was isolated and the bottommost zones were selectively stimulated enhancing the injection and thus improving sweep efficiency. Since the crosslinked gel system is not prone to any disintegration when in contact with acidic interventions, the treatment ensures a superior longevity of the conformance control when compared to other conventional diversion or zonal shut-off treatments.
The success of the treatment substantiates that the CT deployed low viscosity, low concentration delayed crosslinked gel system application can be successfully extended to selective water shut-off applications in producer wells. The injector profile modification treatment executed offered a comprehensive solution to conformance issues enhancing volumetric sweep efficiency, pressure maintenance across depleted sands and avoiding further water cycling in producer wells.
Steam injection is a widely used oil-recovery method that has been commercially successful in many types of heavy-oil reservoirs, including the oil sands of Alberta, Canada. Steam is very effective in delivering heat that is the key to heavy-oil mobilization. In the distant past in California, and also recently in Alberta, solvents were/are being used as additives to steam for additional viscosity reduction. The current applications are in field projects involving steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS).
The past and present projects using solvents alone or in combination with steam are reviewed and evaluated, including enhanced solvent SAGD (ES-SAGD) and liquid addition to steam for enhancing recovery (LASER). The use of solvent in other processes, such as effective solvent extraction incorporating electromagnetic heating (ESEIEH) and after cold-heavy-oil production with sand (CHOPS), are also reviewed. The theories behind the use of solvents with steam are outlined. These postulate additional heavy-oil/bitumen mobilization; oil mobilization ahead of the steam front; and oil mobilization by solvent dispersion caused by frontal instability. The plausibility of the different approaches and solvent availability and economics are also discussed.
The U.S. fuels infrastructure has undergone significant changes in the last several years. These changes are in response to shifts in domestic production, imports and exports, processing and distribution. The objective of this analysis is to define and model the U.S. fuels infrastructure, from production, transportation, and processing of crude oil to the distribution, storage, and consumption of refined products, and assess resiliency to natural disasters. This has become a pressing concern in the wake of Hurricane Harvey's impacts on U.S. infrastructure and fuels markets.
The analysis was conducted through a detailed assessment of the petroleum infrastructure, including wells, pipelines, refineries, crude and product terminals, import and export facilities, natural gas storage and processing facilities, and other key components. Interdependencies between petroleum and other types of infrastructure were also evaluated. As part of this analysis, a wide range of natural disasters, including earthquakes, hurricanes, tsunamis, and wildfires, were considered. For each of these natural threats, the geographic risks, the severity and type of damage, the likelihood of that damage, and the time required for recovery were all established using the latest available research.
To complete the analysis several tools were developed and applied. These include a comprehensive geospatial system used to identify major markets and submarkets and to determine dependencies and vulnerabilities; models of the market supply/demand requirements; a national disruption model which details the major crude and product markets; and disruption models to predict the impact on crude and refined products from hurricanes, earthquakes, and tsunamis.
The analysis showed that the U.S. fuels infrastructure is vulnerable to being impaired by natural disasters. Furthermore, the interdependencies of the infrastructure, in terms of both type of infrastructure and geographic location, leave the U.S. vulnerable to cascading risks. As part of the study, potential mitigation efforts were determined to address regional and national vulnerabilities. The proposed mitigation efforts have been incorporated into the Department of Energy's recent Quadrennial Energy Review. This study provides an update and extension of work performed earlier.
The paper provides a detailed assessment of the U.S. fuels infrastructure and its vulnerabilities to natural threats. These include earthquakes, hurricanes, and other disasters. For each of these threats, the geographic risks, as well as the type, probability, and severity of damage, are discussed. Finally, case studies of recent disasters, including the impact of Harvey on the Gulf Coast, Midcontinent, and East Coast, are used to illustrate the fuels infrastructure vulnerabilities and the need for mitigation.
Aldhaheri, Munqith (Missan Oil Company) | Wei, Mingzhen (Missouri University of Science and Technology) | Alhuraishawy, Ali (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
Polymer bulk gels have been widely applied to mitigate excessive water production in mature oil fields by correcting reservoir permeability heterogeneity. This paper presents a comprehensive review of the water responses and the economic assessments of injection-well gel treatments. The survey includes 61 field projects implemented between 1985 and 2014 and compiled from SPE papers and U.S. DOE reports. Ten parameters were evaluated according to the reservoir lithology, formation type, and recovery process using the univariate analysis, stacked histograms, and scatterplots.
Results indicated that gel treatments have very wide ranges of water injection/production responses and economic indicators. We identified that gel treatments do reduce the water production but not dramatically to really low levels. The water production continues to increase after the proactive treatments applied in undeveloped conformance problems at low water cuts (<50%). Contrarily, the water production decreases after the reactive treatments conducted in developed conformance issues at high water cuts (>50%). When successfully applied, gel treatments averagely reduce the water injection rate by 34% and the water cut by 10%; however, the water cut may also increase by 17%. For developed problems, the water cut may stabilize or increase after the remediation mainly in matrix-rock sandstone reservoirs, especially when small gel volumes are injected (<1000 barrels) into this formation type.
Economically, gel treatments are appraised solely based on the oil production response and both water responses are not considered in the evaluation. Typically, gel treatments have cost of incremental oil barrel of 2$/barrel and payout time of 9.2 months and function for 1.9 years. They have better water responses and economics in carbonates than in sandstones and in unconsolidated and naturally-fractured than in matrix-rock formations; however, they have reverse tends with respect to the gel effective time. The gel effective time significantly decreases with the channeling strength, the aperture of flow channels, and the temperature of injected drive-fluids. Generally, the water production response and economic parameters improve as the injected gel volume increases and the treatment timing advances in the flooding life. For different application environments, the present review provides reservoir engineers with updated ideas about what are the low, typical, and high performances of gel treatments when applied successfully and how other treatment aspects affect the performances.
A tertiary alkaline/surfactant/polymer (ASP) multi-well pilot flood was carried out in the San Francisco field, Colombia. The pilot had mixed results, as the positive subsurface response was counterbalanced by serious operational issues, that in the end did not allowed the pilot to realize its full potential. The complexity of the flow paths in a multi-sand reservoir with irregular well spacing lead to large quantities of chemicals being recirculated, which trigger the operational issues, becoming a complex loop where these issues led to closing wells, which led to changing the flow paths and generating more operational issues. The paper presents the design of the pilot, the extensive work that was carried out to understand and improve the flow in the pilot area, the response of the pilot, the challenges that were faced during its operation, and the analysis and lessons learned from this pilot.
Izadi, M. (Ecopetrol S.A.) | Vicente, S. E. (Ecopetrol S.A.) | Zapata Arango, J. F. (Ecopetrol S.A.) | Chaparro, C. (Ecopetrol S.A.) | Jimenez, J. A. (Ecopetrol S.A.) | Manrique, E. (Ecopetrol S.A.) | Mantilla, J. (Ecopetrol S.A.) | Dueñas, D. E. (Ecopetrol S.A.) | Huertas, O. (Ecopetrol S.A.) | Kazemi, H. (Colorado School of Mines)
Surfactant-polymer (SP) flooding (also known as micellar flooding) is an enhanced oil recovery (EOR) process resulting from the interaction of three mechanisms: (1) oil solubilization, (2) interfacial tension reduction, and (3) aqueous-phase mobility reduction by polymer. Surfactant-polymer flooding has been studied both in the laboratory and field pilot tests for several decades. In SP flooding, traditionally a tapered polymer solution follows the injected surfactant slug. However, in recent years, co-injection of surfactant and a relatively high concentration of polymer solution has been used in several field trials. Despite a significant increase in oil recovery in several surfactant-polymer flood projects, the increased oil production period has been of short duration.
The first objective of this paper is to present two field pilot tests which encountered productivity impairment, and the second objective is to describe the probable causes of the productivity impairment. The third objective of the paper is to present a methodology, using field and laboratory data, to anticipate the nature of long-term problems. To shed light on the issues, we will present two pilot tests located in the Illinois basin in the United States and San Francisco Field in Colombia. The results of the pilot tests and several laboratory experiments will be presented to address the productivity loss observed in the two pilot projects. Laboratory measurements to determine crude oil propensity for emulsions, with and without surfactants, are not part of the routine chemical EOR protocol in the industry. Nonetheless, understanding the cause and type of emulsion formation in crude oil, brine, and polymer at different salinities is critical and will be presented in the paper. In addition, in the paper, we will present the results of a numerical simulator to evaluate experimental laboratory results and the field test performance. In conclusion, because of the experience with numerous laboratory experiments and the conduct of associated field tests, we will be able to shed light on the complexity of surfactant-polymer EOR field applications.
Aldhaheri, Munqith (Missan Oil Company, Dept. of Petroleum Engineering, University of Misan) | Wei, Mingzhen (Missouri University of Science and Technology) | Zhang, Na (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
As lifespan extenders, bulk gels have been widely applied to rejuvenate oil production from uneconomic producers in mature oilfields by improving sweep efficiency of IOR/EOR floodings. This paper presents a comprehensive review for the responses of injection-well gel treatments implemented between 1985 and 2014. The survey includes 61 field projects compiled from SPE papers and U.S. DOE reports. Seven parameters related to the oil production response were evaluated according to the reservoir lithology, formation type, and recovery process using the univariate analysis and stacked histograms. The interquartile range method was used to detect the under-performing and over-performing gel projects. Scatterplots were used to identify effects of the injected gel volume and the treatment timing on the treatment responses.
Results indicated that gel treatments have very wide ranges of responses for injection and production wells and for oil and water rates/profiles. The typical incremental oil production is 116 MSTBO per treatment, 15 STBO per gel barrel, or 10 STBO per polymer pound. We identified that gel treatments perform more efficiently in carbonate than in sandstone reservoirs and in naturally-fractured formations than in other formation types. In addition, the incremental oil production considerably increases with the channeling strength and the injected gel volume for all formation types, not just for the matrix-rock reservoirs. Moreover, gel treatments applied in naturally-fractured formations have lower productivities in sandstones than in carbonates based on the normalized performance parameters.
Declining tends were identified for all parameters of the oil production response with the treatment timing indicators. The sooner the gel treatment is applied; the faster the response and the larger the incremental oil production and its rate. It is recommended to allow longer evaluation times for gel treatments applied in matrix-rock formations or in mature polymer floodings as their response times may extend to several months. Gel treatments would perform more efficiently if they are conducted at water cuts <70%, flood lives <20 years, or recovery factors <35%. For different application environments, the present review provides reservoir engineers with updated ideas about what are the low, typical, and high performances of gel treatments when applied successfully and how other treatment aspects affect the performances.
Leon, J. M (Ecopetrol, S.A) | Izadi, M. (Ecopetrol, S.A) | Castillo, A. (Ecopetrol, S.A) | Zapata, J. F. (Ecopetrol, S.A) | Chaparro, C. (Ecopetrol, S.A) | Jimenez, J. (Ecopetrol, S.A) | Vicente, S. E. (Ecopetrol, S.A) | Castro, R. (Ecopetrol, S.A)
The Dina Cretaceous field, operated by Ecopetrol S.A., is located in the Upper Magdalena Valley (UMV) Basin in Colombia. The field discovered in 1969, reaching maximum primary oil rate of 6,500 BOPD in May 1980. Secondary recovery mainly by peripheral water injection started in 1986, achieving a maximum production of 9,850 BOPD in January 1988. Subsequently, water production has increased rapidly accompanied by declining oil production, due primarily to reservoir heterogeneity and an unfavorable mobility ratio. The oil recovery factor as of October 2017, as a percentage of OOIP, is estimated to be approximately 33% at a current water cut of about 97%.
Ecopetrol S.A in 2009, began to look for new development strategies that would allow optimizing the oil recovery for this asset. Several IOR/EOR technologies were screened to reduce water production and increase sweep efficiency. Polymer gels ("Conformance treatments"), polymer flooding and cross-linked polymer also known as Colloidal Dispersion Gels (CDG) are some of the technologies most commonly used during the last few decades for this purpos. Based on screening study, detailed production and injection data analysis, water channeling, reservoir heterogeneity, adverse mobility ratio, laboratory evaluation and simulation results, the cross-linked polymer systems (CDG) were implemented in four patterns between 2011 and 2015. This would allow to increase the volumetric sweeping efficiency both for mobility control, in-depth conformance control and leading to viable project both technically and economically.
This paper presents the implementation and results of the injection of cross-linked polymer systems in the Dina Cretaceous field. A summary of the maturation process is presented, from conceptual design, experimental evaluation, engineering analysis, numerical simulation, pilot execution, process monitoring and field expansion strategy, as well as the results obtained in the pilot.
The results of the pilot were satisfactory both technically and economically and lead to a new development plan for the field. This new plant is focused on the optimization of the waterflood, pattern reconfiguration, infill drilling, selective injection, and improving the sweep efficiency through the injection of cross-linked polymer across the field in 11 more patterns.