This paper addresses two questions for polymer flooding. First, what polymer solution viscosity should be injected? A base-case reservoir-engineering method is present for making that decision, which focuses on waterflood mobility ratios and the permeability contrast in the reservoir. However, some current field applications use injected polymer viscosities that deviate substantially from this methodology. At one end of the range, Canadian projects inject only 30-cp polymer solutions to displace 1000-3000-cp oil. Logic given to support this choice include (1) the mobility ratio in an unfavorable displacement is not as bad as indicated by the endpoint mobility ratio, (2) economics limit use of higher polymer concentrations, (3) some improvement in mobility ratio is better than a straight waterflood, (4) a belief that the polymer will provide a substantial residual resistance factor (permeability reduction), and (5) injectivity limits the allowable viscosity of the injected fluid. At the other end of the range, a project in Daqing, China, injected 150-300-cp polymer solutions to displace 10-cp oil. The primary reason given for this choice was a belief that high molecular weight viscoelastic HPAM polymers can reduce the residual oil saturation below that expected for a waterflood or for less viscous polymer floods. This paper will examine the validity of each of these beliefs.
The second question is: when should polymer injection be stopped or reduced? For existing polymer floods, this question is particularly relevant in the current low oil-price environment. Should these projects be switched to water injection immediately? Should the polymer concentration be reduced or graded? Should the polymer concentration stay the same but reduce the injection rate? These questions are discussed.
This paper presents an overview of the SACROC Unit's activity focusing on different CO2 injection and WAG projects that have made the SACROC Unit one of the most successful CO2 injection projects in the world. The main objective of this work was to review CO2 injection and injection rate losses due to the CO2 /WAG miscible displacement process in the SACROC Unit and recommend an injection strategy for WAG-sensitive patterns.
Two types of pattern CO2 /WAG injection rate performance were observed, 1) WAG-sensitive and 2) WAG insensitive. WAG-sensitive patterns displayed loss of CO2 injectivity, exceeding 80% in some patterns, during water-alternating-gas (WAG) injection, and an apparent reduction in water injectivity during the follow-up brine injection. This injectivity loss was observed in over 150 injection patterns. Over time, CO2 injectivity tended to return to prior-to-WAG values. WAG-insensitive patterns suffer from these injectivity losses and were characterized by differences in 1) injectivity profiles, 2) Dykstra-Parsons coefficients, and 3) injectivity indexes.
In the majority of WAG-sensitive patterns, injectivity profiles redistributed after CO2 injection, while WAG-insensitive patterns did not show a significant change in their injectivity profiles over time. In a limited data set, the mean Dykstra-Parsons coefficient calculated for WAG-sensitive patterns was 0.83, while for WAG-insensitive patterns the mean Dykstra-Parsons coefficient was 0.76. However it was observed that in the lower Dykstra-Parsons patterns (WAG-insensitive patterns) much larger injectivity indexes were also observed; 19.5 bbl/day/psi, compared to 8.5 bbl/day/psi for higher Dykstra-Parsons patterns. This suggests that the WAG-insensitive patterns were dominated by fracture flow rather than matrix flow. These observations indicate that the WAG injection process in these heterogeneous SACROC wells is successful in diverting the injected fluids from zones with higher permeability to zones with lower permeability.
For wells with injectivity values of less than 10 bbl/day/psi it is recommended to begin CO2 /WAG injection with a long CO2 cycle since they are likely to show sensitivity to WAG.
A simulated 5-spot pattern was used to study the injection schedule for WAG-sensitive patterns. Longer CO2 cycles and shorter water cycles improved the injectivity and pattern production. Most importantly, it was observed that increasing producing BHP to MMP resulted in significantly lower GOR.
Mishra, Ashok (Conoco Phillips) | Abbas, Sayeed (Conoco Phillips) | Braden, John (Conoco Phillips) | Hazen, Mike (Conoco Phillips) | Li, Gaoming (Conoco Phillips) | Peirce, John (Conoco Phillips) | Smith, David D. (Conoco Phillips) | Lantz, Michael (TIORCO, a Nalco Champion Company)
This paper is a field case review of the process and methodologies used to identify, characterize, design, and execute a solution for a waterflood conformance problem in the Kuparuk River Unit in late 2013. In addition, post treatment analysis in a complex WAG flood will be discussed. The Kuparuk River Field is a highly fractured and faulted, multi-layer sandstone reservoir located on the North Slope of Alaska. Large scale water injection in the field was initiated in 1981 and overall the field responded favorably to waterflood operations. In 1996, Kuparuk implemented a miscible WAG flood in many areas of the field. However, natural fault and fracture connectivity has resulted in some significant conformance issues between high angle wells in the periphery. Methodologies employed to identify and characterize one specific conformance issue will be outlined. Details of diagnostic efforts, and how they were used to identify, characterize and mitigate an injector/producer interaction through a void space conduit will be discussed. The solution selected to resolve this conformance issue involved pumping a large crosslinked hydrolyzed polyacrylamide (HPAM) gel system. The solution used a tapered concentration design with one of the highest molecular weight HPAM polymers available. Before execution of this solution, extensive history matching and modeling of the solution design and benefits were used to justify this effort. These modeling efforts and their projections will be reviewed. This solution was pumped into the offending injector in late 2013, and offset producers were carefully monitored for gel breakthrough. The polymer treatment design parameters, including rates and pressure limits were used to generate an effective solution. A discussion of this active design approach, a complete review of the well problem dynamics, treatment operations, products used, and potential complications associated with these products will be discussed. Post solution execution performance analysis was difficult due to the active nature of this MWAG flood. A variety of plotting and analysis techniques were used to identify and quantify the results. A discussion of these results will be provided. Finally, a summary of lessons learned, and a limited discussion of future plans will be presented.
We study Enhanced Oil Recovery (EOR) through Low Salinity (LS) waterflooding in a brown oil field. LS waterflooding is an emerging EOR technique in which water with reduced salinity is injected into a reservoir to improve oil recovery, as compared with conventional waterflooding, in which High Salinity (HS) brine or seawater are commonly used. The efficiency of this technique can be quantified at the well-scale by a Single Well Chemical Tracer Test (SWCTT), which is an in-situ method for measuring the Remaining Oil Saturation (ROS) after flooding the near-wellbore region with a displacing agent. Two SWCTTs were executed on a sandstone North African field. The tests were realized in sequence with seawater and LS water to evaluate the EOR potential at the well-scale.
Here, we propose the interpretation of these two SWCTTs. They were modeled through numerical simulations because of the presence of several non-idealities in the complex scenario considered. A recently-developed tracer simulator was employed to solve the reactive transport problem. This was used as a fast post-processing tool coupled with a conventional reservoir simulator. Model parameters were estimated within an inverse modeling framework, on the basis of an assisted history matching procedure that exploits the Metropolis Hastings Algorithm (MHA). Results were scaled up on a sector model of the field, and forecast scenarios that consider a field-scale implementation of this technique were defined.
The well-scale displacement efficiency gain associated with LS water, as compared with seawater, was evaluated. It was quantified as a ROS reduction of 8 saturation unit (s.u.), with a P10–P90 range of 3–15 s.u. Reservoir-scale simulations suggest that the associated ultimate oil recovery of the EOR pilot may be increased by 2% with LS water, with a P10–P90 range of 0.7–4.3%.
Overall, the LS EOR potential for a selected field was quantified through a robust and original workflow, based on SWCTT interpretation. This state-of-the-art procedure is now available for further applications. The simulated oil recovery improvement with LS water is promising, and leads the way to the implementation of an inter-well field trial.
This paper presents the integrated approach for the redevelopment of the waterflood in Howard-Glasscock field located primarily in Howard County, Texas. Originally discovered in 1925, the majority of production is now commingled across the Guadalupe, Glorieta and Clearfork formations. This is a mature field which is currently in the midst of a 5 and 10 acre infill drilling program that began in 2009. Emphasis has primarily been focused on drilling producing wells, but the basis for this project was to optimize an existing waterflood to guide the development strategy of the field moving forward.
A study of the production of the wells drilled since 2009 identified stronger performance in wells with offset waterflood support. On average, waterflood was responsible for a 22% improvement in the expected recovery per well, despite a lack of patterns or a comprehensive waterflood management plan. As a result, a multi-disciplined team was commissioned to design a strategy for the redevelopment of the flood and more active management of the daily operations. Geology and reservoir engineering aspects were used to characterize the reservoir in conjunction with classical waterflood methods to understand the current performance and validate the expectations for secondary recovery.
Fracture orientation was studied based on cases of early breakthrough and was utilized in pattern identification and well placement to maximize sweep and discourage direct communication between injectors and producers. Further, the success of the waterflood in Howard-Glasscock relies on the ability to control the flow of water over a 2,000 foot vertical interval. To address this, the team has implemented a surveillance plan with improved monitoring and communication with the operations team to enhance the collection of data and in order to react to the dynamics of a waterflood. The rapid response to injection observed in this field requires proper surveillance and timely control of water flow which ultimately drives the success of the program by moving water from high water cut intervals to bypassed oil zones.
This paper details the systematic approach that was used to design the redevelopment plan for a waterflood in a 90 year old field. The scope of work is being implemented and represents an adjustment in the development plan of Howard-Glasscock moving forward. Ultimately, the enhanced performance observed in recent drilling programs and the continued success of development in this mature field hinges on understanding and managing the waterflood moving forward.
Oglesby, Kenneth D. (Impact Technologies LLC) | D'Souza, David (Denbury Resources) | Roller, Chad (MidCon-Energy Partners LP) | Logsdon, Ryan (MidCon-Energy Partners LP) | Burns, Lyle D. (Clean Tech Innovations, LLC) | Felber, Betty J. (EOR Consultant)
Field test results of a new silicate based Silicate-Polymer-Initiator (SPI) gel system for zonal conformance control are presented from: 3 treatments in a central Mississippi sandstone carbon dioxide (CO2) flood, including 1 producer; 5 injector treatments in a mature, west Texas San Andres dolomite, CO2 flood under Water-Alternating-Gas (WAG) operation; and 2 injector treatments in a northeast Oklahoma waterflood. Gel treatment volumes ranged from 130 to 4,349 barrels of the patented, environmentally friendly, silicate gel system that is pumped at a near water viscosity and density. That pre-gel liquid is triggered to a gel by a pH change caused by external or internal initiation methods. One unique aspect of these silicate solutions is that they can be initiated by both the pre- and post-treatment injected CO2 itself. Alternately, other external and internal initiators can be used in both CO2 and water-floods. Targeted gel times ranged from 1 hour up to 6 days, with maximum gel strength generated within 2–4 weeks. The resultant silicate gels are 10 times stronger than any known gelled polymer system, per CTI laboratory Extrusion and Penetrometer testing. Selected additives were utilized in the gel treatment fluids to focus the pre-gelled solutions into the desired high permeability zones. Furthermore, pre-gel fluid entry into water or oil zones will not set the silicate gel, but will instead dilute the leading edge.
Rate, pressure, injectivity and downhole profile surveys were used to evaluate the treatment in injection wells. Oil, water and gas rates, Water: Oil Ratios, Gas: Oil Ratios and CO2 utilization efficiency were used to evaluate treatments in production wells. Offset production wells were monitored, where possible, for production changes, sometimes seen outside the prior established patterns. Where the data was available, the new silicate gel field treatments were directly compared to prior polyacrylamide and similar conformance systems. In most cases, the new silicate system exhibited positive responses while previous polymer based systems did not respond.
The application of surfactants to improve oil recovery in conventional reservoirs via wettability alteration and enhancement of spontaneous imbibition has been extensively studied in the literature. However, little work has been performed yet to investigate the interaction of these surfactants with ultra-tight oil-rich shale reservoirs such as Wolfcamp shale. The use of horizontal drilling and massive multistage hydraulic fracturing has made primary oil recovery from these ultra-tight oil-rich shale reservoirs possible. With declining production from existing shale wells, it is essential to explore potential "beyond primary" strategies in shale oil development. This paper analyzes the potential of surfactants in altering wettability and improving the process of spontaneous imbibition in oil rich shales demonstrating nanodarcy range permeability, relevant to stimulation and "beyond primary" chemical EOR applications in shales.
Novel proprietary surfactant blends along with traditional nonionic surfactants were investigated in this study using Wolfcamp shale core samples exhibiting nanodarcy permeability. X-ray diffraction analysis was performed which indicated that Wolfcamp shale has mixed mineralogy, with quartz, calcite, and dolomite acting as the major minerals in varying proportions depending on the interval depth. Contact angle and interfacial tension measurements were performed at reservoir temperature to identify the state of native wettability and the impact of surfactants in altering wettability. Thereafter, spontaneous imbibition experiments were performed using 3D computed tomography methods to understand the improvement in the magnitude of imbibition penetration due to surfactant addition. Contact angle and spontaneous imbibition experiments showed that Wolfcamp shale is intermediate-wet and surfactants have the potential to alter the native wettability to a preferentially water-wet state and improve oil recovery due to enhanced spontaneous imbibition.
Surfactants which altered the wettability significantly, but lowered the interfacial tension only slightly showed the highest oil recoveries due to the creation of strong capillary driven forces directly responsible for effective spontaneous imbibition. The potential of surfactants in altering wettability and improving oil recovery via enhanced spontaneous imbibition in ultra-tight oil-rich shales was verified in this study. The effectiveness of traditional nonionic surfactants in altering wettability and improving oil recovery was found to be comparable to that of novel, more expensive proprietary surfactant blends, and hence, the traditional nonionic surfactants provide a cost effective option for stimulation and EOR applications in Wolfcamp shale. Overall, this paper presents the theory behind surfactant interaction with ultra-tight shales and provides experimental results to validate the viability of surfactant induced improved oil recovery in shales.
SmartWater flooding through injection of chemistry optimized waters by tuning individual ions is recently getting more attention in the industry for improved oil recovery in carbonate reservoirs. Most of the research studies described so far in this area have been limited to studying the interactions at rock-fluids interfaces by measuring contact angles, zeta potential, and adhesion forces. The other widely reported interfacial tension data at oil-water interfaces do not consider the formation of interfacial monolayer and the interfacial tension is estimated as an average parameter relying on the properties of two individual bulk phases. As a result, such measurements have serious shortcomings to provide any details on complex microscopic scale interactions occurring directly at the interface between crude oil and water to understand the SmartWater flood recovery mechanism.
In this study, two novel interfacial instruments of interfacial shear rheometer and surface potential sensor were used to study microscopic scale interactions of various individual water ions at both air-water and complex crude oil-water interfaces. The measured interfacial rheology data indicated totally different interfacial behavior at crude oil-water interface when compared to air-water interface due to presence of crude oil functional groups. Viscous dominated response was observed at crude oil-water interface for all brine compositions. These interfaces behaved like a viscous fluid without exhibiting viscoelastic solid like properties. Lower interfacial viscous modulus was observed for certain key ions such as calcium, magnesium, and sodium. The interfacial viscous modulus was found to be substantially much higher for sulfates, besides exhibiting some elasticity. The surface potential was gradually decreased by replacing seawater with calcium only brine. The better surface activity with seawater can be attributed to adsorption of more key water ions at the surface.
The interesting results observed with certain water ions at fluid-fluid interfaces are expected to work in tandem with rock-fluids interactions to impact oil recovery in SmartWater flood. At first, they play a role to control the accessibility of active water ions to approach the rock surface, interact with it and subsequently alter wettability. Next oil droplets adhering to the rock surface will be detached and released due to favorable interactions occurring at rock-fluids interfaces. The interfacial film between oil and water can then quickly be destabilized due to less viscous interfaces observed with certain ions to promote drop-drop coalescence and easy mobilization of released oil droplets. This coalescence process is sequential and it would continue until the formation of small oil bank.
This is the first study that showed added importance of fluid-fluid interactions in SmartWater flood by using direct measurements on individual water ions at crude oil-water interface. In addition, a new oil recovery mechanism was proposed by combining both the interactions occurring at fluid-fluid and rock-fluids interfaces. The new fundamental knowledge gained in this study will provide an important guidance on how to synergize water ion interactions at fluid-fluid interfaces with those at rock-fluids interfaces to optimize oil recovery from SmartWater flood.
Enhanced-oil-recovery techniques by gas injection in shale reservoirs have been introduced and investigated. Laboratory and simulation works have shown good results for enhanced shale oil recovery, but one problem with gas injection is asphaltene precipitation and deposition. Damage due to asphaltene precipitation and deposition in conventional reservoirs has been reported in the literature. In shale reservoirs, pore and throat sizes are much smaller than in conventional reservoirs. Thus, large asphaltene aggregates may cause more serious problems in shale reservoirs.
This experimental study used a nanofiltration technique to investigate the size of asphaltene aggregates precipitated during CO2 and CH4 injection in a shale oil sample. Nano membranes of 200nm, 100nm and 30nm were used to filtrate oil samples injected with different mole fractions of CO2 and CH4 gas. The distribution of asphaltene aggregates’ size at different injected CO2 and CH4 concentrations were obtained and compared with the pore size distribution data of shale cores measured by mercury intrusion porosimeters. Results showed that a higher injected CO2 and CH4 concentration caused more asphaltene precipitation and growth in asphaltene aggregates’ size. The precipitated asphaltene particle size was large enough to cause a pore-blocking problem in tested shale cores.
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.