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.
Enick, Robert M. (Dept. of Chemical and Petroleum Engineering, University of Pittsburgh) | Lee, Jason J. (Dept. of Chemical and Petroleum Engineering, University of Pittsburgh) | Cummings, Stephen D. (Dept. of Chemical and Petroleum Engineering, University of Pittsburgh) | Zaberi, Husain A. (Dept. of Chemical and Petroleum Engineering, University of Pittsburgh) | Beckman, Eric J. (Dept. of Chemical and Petroleum Engineering, University of Pittsburgh) | Dailey, Chris (Special Core Analysis Laboratories, Inc.) | Vasilache, Mihai (Special Core Analysis Laboratories, Inc.)
In this study, we propose a CO2-polymer solution for conformance control agent in order to divert the subsequently injected CO2 away from thief zones and toward lower permeability oil-rich zones. A novel CO2-soluble polyfluoroacrylate (PFA) was synthesized. PFA is an amorphous, sticky, transparent, homopolymer that dissolves readily in CO2 at temperatures and pressures commensurate with CO2 EOR. PFA is based on a monomer that contains six (rather than eight) fluorinated carbons, thereby eliminating the environmental concerns associated with possible degradation products. Because PFA has high molecular weight, the addition of ~1wt% PFA to CO2 thickened CO2 by a factor of about four. Nnumerous core floods were then conducted to determine if the adsorption of PFA onto the rock surfaces could provide conformance control. When a CO2-PFA solution is injected into porous media, a portion of the dissolved PFA strongly adsorbs onto the mineral surfaces, regardless of what fluid was originally present in the pores. Because PFA is highly hydrophobic and oil-phobic, the thin PFA film deposited on the rock surfaces changes the wettability and dramatically reduces the permeability of the rock (especially sandstone) for subsequently injected fluids. This strong adsorption and change in wettability significantly reduces the permeability of the rock to subsequently injected brine or CO2. Dual parallel core floods were conducted to demonstrate the efficacy of PFA-CO2 solutions for conformance control. Excellent results were obtained when a CO2-PFA solution was injected solely into an isolated high permeability (80 mD) Berea sandstone core (the thief zone) that was previously flooded with brine and CO2. After this treatment, the Berea core was then placed in parallel with a 20 mD Carbon Tan sandstone core. All of the subsequently injected CO2 was diverted to the Carbon Tan core. Similar results were obtained with dual parallel limestone cores. To the best of our knowledge, PFA is the first known example of a CO2-soluble polymeric conformance control agent.
Yao, Chuanjin (China University of Petroleum) | Xu, Xiaohong (China University of Petroleum) | Wang, Dan (China University of Petroleum) | Lei, Guanglun (China University of Petroleum) | Xue, Shifeng (China University of Petroleum) | Hou, Jian (China University of Petroleum) | Cathles, Lawrence M. (Cornell University) | Steenhuis, Tammo S. (Cornell University)
Micron-size polyacrylamide elastic microspheres (MPEMs) are a smart sweep improvement and profile modification agent, which can be prepared controllably on the ground through inverse suspension polymerization using acrylamide crosslinked with an organic crosslinker. MPEMs can tolerate high temperature of 90 °C, high salinity of 20000 mg/L and wide pH value range of 4.0–10.3. MPEMs suspension almost has no corrosion effect on the injection pipeline and equipment. MPEMs can suspend in produced water easily and be pumped into formation at any rate. More importantly, MPEMs can reach the designed size after hydration swelling in oil formation and a reliable blockage can be formed; MPEMs can deform elastically and move forward step by step to realize a moveable sweep improvement and profile modification process in reservoirs. The pore-scale visualization experiment shows that there are four migration patterns for MPEMs transport in porous media and they are smooth passing, elastic plugging, bridge plugging and complete plugging. MPEMs can deform depending on their elasticity and pass through these pore-throats. Parallel-sandpack physical modeling experiment under the simulated reservoir conditions shows that MPEMs mainly enter into and plug high permeability layer whose permeability is reduced from 3.642 µm2 to 0.546 µm2, and almost do not clog low-permeability layer whose permeability is reduced from 0.534 µm2 to 0.512 µm2. Field application results of MPEMs treatment in a serious heterogeneous, high temperature and high salinity reservoir show that MPEMs can effectively improve swept volume and displacement efficiency. Because of the excellent properties, MPEMs treatment will become a cost-effective method for sweep improvement and profile modification to serious heterogeneous, high temperature and high salinity reservoirs with fractures and channels.
One of the primary problems for mature oilfield operators is the production of undesired fluids, such as water or gas. Cantarell is a mature field wherein one of the greatest challenges is managing produced water. Mature oil fields experience severe water production, which can be challenging in naturally fractured carbonate reservoirs that produce through a thick layer of oil. A new technology combining two conformance systems was used to alleviate water production in a well in this field, returning production to optimal levels.
The study well (Well A) was shut in because of high water cut (90 to 100%), and post-analysis of this problem showed water coning from fractures in the Lower Cretaceous formation. The well has a unique interval, and perforating a deeper interval was not possible because the water-oil contact (WOC) was close. The solution selected for this case was a combination of two conformance technologies for water control that permit sealing high permeability channels and fractures and, more importantly, help provide selective water control—one is a swelling polymer designed to shut off water channels, fractures, or highly vugular zones, and the other is hydrocarbon-based slurry cement that reacts on contact with water. The result was the recovery of a producer well with 1,197 BOPD with 14% water cut. After 19 months, production averaged 1,300 BOPD for that month with 40 to 66% water cut.
Correctly diagnosing the problem and combining conformance technologies can help operators resume production of wells considered lost because of undesired fluids production. Therefore, this technology could be used to benefit reservoir optimization and production.
Qiu, Yue (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Geng, Jiaming (Missouri University of Science and Technology) | Wu, Fengxiang (Daqing Xinwantong Chemical Co. Ltd.)
This paper presents the detailed descriptions of successful field application for a high-temperature and high-salinity resistance microgel in a mature reservoir in the northwest part of China. The reservoir with low permeability (230 md) experienced serious vertical and lateral heterogeneity problems, which caused low sweep efficiency and high water-cut (more than 95%). The treatment was designed based on laboratory experiments and experience from previous field application, providing detailed information of mechanism of microgel treatment and project execution. Thermal stability test showed that the microgel could resist the salt concentration up to 230,000 ppm at 125 °C for more than 1 year. From the core analysis, permeability of the long-term water-flooded zone was measured around 1,489 md, proving the evidence that high-permeability zones existed. Pilot test has been done before field application and valuable experience about how to design the injection parameters was provided. According to the information from laboratory experiments and the pilot test, four injection wells associated with nine offset production wells were selected for microgel treatment. For about 10 months treatment, 169 t of microgel was injected by five slugs.
Gradually increased injection pressure suggested that microgel could be placed deeply into the reservoir. The ultimate incremental oil production was approximately 29,635.8 t with the water cut decreasing from 95.3% to 93.1%. Microgel can be successfully used in relative low permeability (230 md) reservoir with harsh conditions for conformance control.
Imqam, Abdulmhsin (Missouri University of Science and Technology) | Wang, Ze (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Delshad, Mojdeh (The University of Texas at Austin)
Preformed particle gels (PPG) have been successfully applied as a plugging agent to solve the conformance problem in fractured reservoirs. They are injected to plug fractures and then divert displacing fluid into poorly swept zones and areas. However, PPG propagation and plugging mechanisms through open fractures have not been studied thoroughly. This paper investigated the influence of some factors (particle size, brine concentration, heterogeneity, injection flow rate, and brine salinity) on gel injectivity and plugging performance for water flow through opening fractures. Five-foot tubes were used to mimic opening fractures. Three models were designed to gain understanding on how fracture geometry and PPG properties affect gel injection and plugging efficiency, including (1) single fracture with uniform fracture width, (2) single fracture with different widths, and (3) two parallel fractures with different width ratios between each other. Results from single uniform fracture experiments showed that PPG injection pressure was more sensitive to gel strength than gel particle size. When large PPG size and high gel strength were used, high injection pressure and large injection pore volume were required for PPG and brine to reach fracture outlets. Results from single heterogeneous fracture model experiments showed PPG injection pressure increased as the fracture heterogeneity in sections increased. Particle gel accumulated at the choke point within each fracture and caused injection pressure to increase accordingly. Furthermore, results showed that having a lower salinity within a fracture, which was less than the brine salinity that was used to prepare PPG, would improve the PPG plugging efficiency for water flow. Parallel fracture models results showed that when weak PPG was used, a large volume of PPG flowed into a large fracture width and a small portion of the gel particle volume flowed into small fracture width. However, with increased gel strength and fracture width ratio, PPG only flowed through larger fracture widths. This paper demonstrates important impact elements of gel propagation and water flow for different opening fracture situations.
Many offshore heavy oil reservoirs underlain by large aquifer are developed through cold production method: horizontal wells, with water coning/cresting being a major concern. Inflow Control Devices (ICDs) are often used to delay the water breakthrough by balancing the well inflow along the well section. However, ICDs have difficulties to mitigate the water coning/cresting after water breakthrough, leading to water bypass oil, premature well abandonment and low oil recovery. In this study, we propose the use of a dual completion technology, Bilateral Water Sink (BWS), assisted with ICDs to mitigate water coning/cresting in high water cut wells, therefore improving oil recovery for offshore heavy oil underlain by large aquifer.
To investigate the reservoir performance under this new production technique, a series of experiments were conducted in a scaled Hele-Shaw model, similar to a cross-section of horizontal wells. Identical flow behavior at each cross-section perpendicular to the well axis were assumed. The experiments resemble to the situation in which the ICDs have been successfully implemented to provide a uniform flow along the entire well section. The oil recovery, water cut and reservoir pressure were measured in each runs to quantify the effects of BWS wells on water coning/cresting mitigation and improving oil recovery.
The experimental results show that while ICDs mitigate the non-uniform production profile along the horizontal well section, BWS wells mitigate the water coning/cresting by dynamically modifying the pressure distribution in the reservoir. Experimental results also verify that the previously derived theoretical rates in BWS can efficiently suppress the water coning/cresting after water breakthrough. The quantitative and qualitative results demonstrate that BWS could reduce the water cut from over 95% in high water cut horizontal wells to less than 40 % and improve the heavy oil recovery about 4-6 times compared with that of conventional horizontal wells.
Those findings provide a new insight into offshore heavy oil production mechanism. Because of BWS's ability of converting an original bottom water drive system to a more effective edge water drive system, low water cut and high oil recovery can be achieved by utilizing the reservoir energy without using of heat.
Aldhaheri, Munqith N. (Missan Oil Company, Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
Polymer gels are increasingly applied to improve sweep efficiency of different IOR/EOR recovery processes. Three in-situ polymer gel systems including bulk gels, colloidal dispersion gels, and weak gels are often used to mitigate water production caused by reservoir heterogeneity and unfavorable mobility ratio of oil and injected fluids. Selecting the most appropriate gel system is a key component for a successful conformance improvement treatment. Screening criteria in terms of reservoir and fluid characteristics have been widely used to identify potential technologies for a specific reservoir. Despite the large number of polymer gel projects, only five, limited-parameters, single-agent criteria or surveys have been sporadically accomplished that suffer from many deficiencies and drawbacks.
This paper presents the first complete applicability guidelines for gel technologies based on their field implementations in injection wells from 1978 to 2015. The data set includes 111 cases histories compiled mainly from SPE papers and U.S. Department of Energy reports. We extracted missing data from some public EOR databases and detected potential outliers by two approaches to ensure data quality. Finally, for each parameter, we evaluated project and treatment frequency distributions and applicability ranges based on successful projects. Extensive comparisons of the developed applicability criteria with the previous surveillance studies are provided and differences are discussed in details as well.
In addition to the parameters that are considered for other EOR technologies, we identified that the applicability evaluations of polymer gels should incorporate the parameters that depict roots and characteristics of conformance issues. The present applicability criteria comprise 16 quantitative parameters including permeability variation, mobility ratio, and three production-related aspects. Application guidelines were established for organically crosslinked bulk gels for the first time, and many experts' opinions in the previous criteria were replaced by detailed property evaluations. In addition, we identified that the applicability criteria of some parameters are considerably influenced by lithology and formation types, and thus, their data were analyzed according to these characteristics. Besides their comprehensiveness of all necessary screening parameters, the novelty of the new criteria lies in their ability to self-check the established validity limits for the screening parameters which resulted from the inclusion and simultaneous evaluation of the project and treatment frequencies.