This paper describes the use of advanced completions employing passive inflow control devices (ICD) and autonomous inflow control devices (AICD) in multi-zone horizontal wells to improve the distribution of gas injection and to restrict premature production of gas in gas injection soak EOR process for unconventional oil wells.
The recovery efficiency of unconventional oil reserves is very low due to the micro-permeability of these reservoirs and rapid depletion of pore pressure proximal to the fractures and wellbore. Several enhanced oil recovery schemes have been proposed to stimulate production and increase recovery efficiency in these reservoirs by injecting gas or carbon dioxide in fracture stimulated, long horizontal wells, and either producing oil from adjacent wells (gas injection flooding drive mechanism), or by back-producing the injectant and reservoir fluids in the same wellbore after a suitable "soak" period (huff and puff).
The effective distribution of the injected gas in these wells and the ability to keep the gas in the reservoir to maintain energy can greatly affect the recovery efficiency that can be achieved. Advanced completions utilizing appropriately designed ICDs and AICDs can enhance the performance of these EOR schemes.
ICDs can be used to balance the distribution of gas injection along the length of the wellbore, while AICDs can help control the early back-production of gas. The Autonomous Inflow Control Device (AICD) is an active flow control device that delivers a variable flow restriction in response to the properties (viscosity) of the fluid flowing through it. Water or gas flowing through the device is restricted more than oil. When used in a horizontal well, segmented into multiple compartments, this design prevents excessive production of gas after breakthrough occurs in one or more compartments.
The implementation of advanced completions in EOR applications has been studied by reservoir and well performance simulation. This proper use of ICDs and AICDs in these applications can significantly improve recovery efficiency without further well intervention.
To evaluate the performance of the AICD, a comprehensive multi-phase flow model of the autonomous performance has been developed and workflow created for simulation of performance within the reservoir. This paper will describe the experience with the technology and modelling prediction for EOR projects.
Patil, P. D. (The Dow Chemical Company) | Knight, T. (The Dow Chemical Company) | Katiyar, A. (The Dow Chemical Company) | Vanderwal, P. (The Dow Chemical Company) | Scherlin, J. (Fleur De Lis Energy LLC) | Rozowski, P. (The Dow Chemical Company) | Ibrahim, M. (Schlumberger) | Sridhar, G. B. (Schlumberger) | Nguyen, Q. P. (The University of Texas at Austin)
This paper summarizes the overall response from the CO2-foam injection in the Salt Creek field, Natrona County, Wyoming. Conformance control of CO2 by creating foam between supercritical CO2 and brine to improve the sweep efficiency is documented in this paper. The foam was implemented in an inverted fivespot pattern in the Salt Creek field where the second Wall Creek (WC2) sandstone formation is the primary producing interval, with a net thickness of about 80 ft and at a depth of approximately 2,200 ft. The initial phase of the foam pilot design involving identifying the pilot area, performing coreflood experiments, performaing dynamic reservoir simulation for history match, and forecasting with foam have been documented in the literature. As a part of the foam pilot monitoring, a gas tracer study was performed before and after the injection of foam in the reservoir. The initial planning, monitoring, and part of foam response is covered in earlier publications. The last surfactant injection in the field was in June 2016. This paper provides the complete analysis of the results from the foam pilot. The foam pilot was successful in demonstrating the deeper conformance control and improvement in sweep efficiency, which resulted in 25,000 bbl of incremental oil. Also overall, a 22% decrease in CO2 injection amount is realized due to better utilization of CO2 compared to the baseline.
Water alternating gas (WAG) injection is a common technique in enhanced oil recovery. However, gas injection often associates with fingering due to high gas mobility, which leaves a large portion of the reservoir unswept. This study addresses gas mobility control observations through novel X-ray microfocus visualization of core-flood experiments and interpretation aided by numerical simulation. We use foam as our primary mobility control agent for improving conformance.
The experimental setup utilizes an automated fluid injection system monitored by an X-ray microfocus scanner to quantify displacement patterns and saturations during WAG core-flood experiments. The core-flood device – placed within an X-ray shielded cabinet – is wirelessly operated through a computer. The resolution of the images permits observation of not only core scale fingering but also pore-scale displacement. We use a metastable foam with surfactant dissolved in the liquid phase to stabilize the gas diffusion in the liquid and to decrease the permeability and/or lower the apparent gas viscosity.
Results show that saturation patterns and displacement front during WAG injection are highly influenced by bedding orientation and rock heterogeneity. Without gas mobility control during WAG injection, fingering and early breakthrough occur in those cases in which bedding orientation facilitates gas to flow through high permeability layers. In these cases, sweep efficiency is low during early time injection of nitrogen and only improves after injection is prolonged. With gas mobility control, the displacement efficiency is significantly improved. Also, dynamic processes like phase trapping, which could severely impair permeability and overall sweep efficiency, is more clearly visualized with the microfocus technique. Simulation work matches experimental data well and replicates saturation patterns measured experimentally in laminated Berea sandstone samples.
The novel visualization technique presented here provides new pore-scale experimental insight to quantifying WAG displacement in heterogeneous media, a resolution one order of magnitude higher than with medical X-ray CT or other core-scale visualization techniques. The findings are useful for understanding flow regimes in structurally complex and heterogeneous formations.
This work presents the conceptual development and experimental evaluation for a new technique to create blocking foams in matrix rock systems by the injection of the foaming agent dispersed in the hydrocarbon gas stream. This new technique aims at simplifying the operation and reducing costs for the deployment of EOR foams in gas injection based projects, and overcoming the disadvantage of limited reservoir volume of influence obtained in the SAG technique.
A systematic experimental work is implemented to investigate the effect of the dispersed chemical (surfactant) concentration and the gas velocity on the ability to create blocking foams at high pressure and temperature, and using representative consolidated porous medium and fluids coming from the Piedemonte fields in Colombia. The concept behind this new technique is the transfer of chemical foamer from the gas dispersion into the connate or residual waters present in the hydrocarbon reservoirs under exploitation, due mainly to the chemical potential derived from the contrast in chemical concentration between the dispersed phase and the in-situ water.
Results herein confirm that it is possible to create blocking foam by this technique in a consolidated sandstone core at residual oil and water conditions, after being submitted to a gas flooding displacement. This condition is obtained as far as the gas velocity is above a minimum threshold, and the concentration of the active chemical is above certain limit (138 ppm for this case). Successful experiments with foams created by gas dispersed surfactant showed much longer stability periods when compared with results from foams created by the SAG technique at much higher chemical concentration (2,000 ppm). Application of this foams technique was done in a field pilot. About 600 Bbls of foaming solution were dispersed in the hydrocarbon gas stream in one gas injector of a Piedemonte field (Colombia, South America). Gas injectivity in the well was impaired after two weeks of injection, and the oil production well influenced by this injector changed its performance showing incremental oil production and flattening of the gas oil ratio (GOR) shortly after the dispersed chemical injection period. This innovative foams technique could also be extended to other non-condensable gases at field operating conditions like CO2, Nitrogen, Air, and Flue Gas.
Aamodt, G. (ConocoPhillips Skandinavia AS) | Abbas, S. (ConocoPhillips Co) | Arghir, D. V. (ConocoPhillips Skandinavia AS) | Frazer, L. C. (ConocoPhillips Co) | Mueller, D. T. (ConocoPhillips Co) | Pettersen, P. (ConocoPhillips Skandinavia AS) | Prosvirnov, M. (ConocoPhillips Skandinavia AS) | Smith, D. D. (ConocoPhillips Co) | Jespersen, T. (Halliburton Co.) | Mebratu, A. A. (Halliburton Co.)
This paper discusses a field case review of the processes used to identify, characterize, design and execute a solution for a waterflood conformance problem in the Ekofisk Field that developed in late 2012. The Ekofisk Field is a highly-fractured Maastrichtian chalk reservoir located in the Norwegian sector of the North Sea. Large scale water injection in the field began in 1987 and overall the field has responded well to waterflood operations. However, fault reactivation coupled with extensive natural fractures and rock dissolution has resulted in some challenging conformance issues. In late 2014, a solution was executed to control this problem. Details of the diagnostic efforts and how this data was used to identify, characterize and mitigate an injector/producer connection through a void space conduit (VSC) will be outlined and discussed. These diagnostics include pressure transient analysis (PTA), interwell tracers, injection profiles, seismic mapping, fluid rate analysis, fluid composition and temperature monitoring. The importance of this data analysis is the key element necessary to select an effective solution.
The selected approach involved pumping a large tapered nitrified cement treatment into the offending injector, which is believed to be the single largest nitrified cement operation ever pumped within the oil industry. Because of extremely rapid communication with an offset producer, a protective gel was used to reduce the risk of cement entry into that producer. A brief review of alternative mitigation options and the reasons for selecting the nitrified cement treatment will be discussed. Additionally, a complete review of the shutoff technique, product, damage mitigation strategy, and complications associated with timing and coordination in an offshore environment will also be discussed. Finally, a summary of lessons learned, job execution observations, post-treatment performance results over the past three years, and forward plans will be presented. Based on these results it is believed that there are a number of opportunities to add strong value through conformance engineering.
Immiscible Water Alternating Gas (IWAG) is an EOR process whereby water and immiscible gas are alternately injected into a reservoir to provide better sweep efficiency and reduce gas channelling from injectors to producer wells, aiming to stabilize the displacement front and increase contact with the unswept areas of the reservoir. In this work, we present a summary of best practices for laboratory evaluation of IWAG. This work was motivated by observations related to the way laboratory measurements are normally done, which could result in erroneous interpretation if the results were to be used directly for the design of a field application.
The set of best practices were collected from own work expanding over two decades of laboratory work, discussion with experts from laboratory services and research centres, and a comprehensive literature review. They were tested in a laboratory workflow and compared to conventional workflows used by most laboratories. The recommended approach covers steps from sample preparation, experimental setup, measurement protocols, guideline for process design, and data QA/QC for later use in reservoir simulation.
Among the best practices, particular attention is given to the type of fluids and samples used for the measurements based on the strong effect of rock-fluid interactions on the IWAG performance. The layout of the experimental setup, and how the injection and displacement process is done and the flow effects quantified. Other best practices relate to the selection of the WAG slug ratio, and required initial conditions of the core where the laboratory testing is done. The number of cycles in the WAG injection affects the recovery. On the initial condition of the sample, the knowledge of the sample wettability at the start of the WAG is critical since the optimum ratio is influenced by the wetting state of the rock. A WAG ratio of 1:1, which is the most popular in field applications, is not necessarily the most appropriate.
Regarding flow properties, relative permeability should be evaluated under three-phase conditions and making sure hysteresis effects are well captured data in general not readily available. Special attention should be given to the selection of correlations for calculating three-phase relative permeability widely reported in the literature; in most cases they are not accurate for WAG injection since they do not consider special treatment of water-gas cycle.
We present a side by side comparison of the impact on the laboratory results will be given on using recommended best practices to more routine laboratory implementations. These best practices, with focus on immiscible WAG, provide a new unique workflow for the execution of laboratory programs supporting a better understanding of the involved phenomena and providing accurate data for immiscible WAG process design.
Waterflood implementation accounts for more than half of the oil production worldwide. Despite the observations and extensive research from a large number of floods and thousands of simulation studies, managing waterfloods and Enhanced Oil Recovery (EOR) floods is still a technical challenge. A major contributor to this challenge are waterflood induced fractures (WIF). Managing waterfloods is a multivariable problem although WIF are one aspect, it is by no means the only controlling factor.
The best evidence that WIF are one of the main factors controlling flow in reservoirs is the insensitivity of injection pressure to injection rates. With our experience, in hundreds of waterfloods, we have frequently observed this phenomenon in the field data. If fluid flow depended on diffusive Darcy flow alone, we would expect higher injection rates with higher injection pressures. However, it is common to observed relatively constant injection pressures over a wide range of water injection rates. Rapid well communication and changes in water cuts that vary with injection rates also support an interpretation of high permeability induced fractures between injector and producer. In some reservoirs, interwell tracer data can be used to determine the influence of induced fracture features. The interwell tracers usually show very fast water movement.
Induced fractures in waterfloods and EOR projects can be caused by a number of mechanisms such as but not limited to, pressure depletion, changing pressure regimes, thermal effects, or plugging effects. These fractures can either be beneficial to the reservoir performance or effect performance negatively. Benefits include improved injectivity and increased throughput of the displacing fluid. Negative effects can come in the form of reduced volumetric sweep efficiency, impaired ultimate recovery or injected fluid losses out of zone.
Case studies, theory, and available literature from Western Canada will be reviewed in order to suggest and improve reservoir management strategies for waterfloods. We have completed hundreds of waterflood feasibility, waterflood management and EOR flood studies worldwide and continue to be amazed and humbled by the complexity that many waterfloods and EOR floods exhibit due to induced fracturing. WIF and EOR induced fractures (EIF) are common and should be analysed to optimize production. Growth of the WIF, response to waterflood with the presence of WIF, implication of WIF and reservoir management are the main areas which will be addressed.
Mukherjee, Joydeep (The Dow Chemical Company) | Nguyen, Quoc P. (The University of Texas at Austin) | Scherlin, John (Fleurde Lis Energy) | Vanderwal, Paul (The Dow Chemical Company) | Rozowski, Peter (The Dow Chemical Company)
A supercritical CO2 foam pilot, comprised of a central injection well in an inverted 5-spot pattern, was implemented in September 2013 in Salt Creek field, Natrona County WY. In this paper we present a thorough analysis of the pilot performance data that has been collected to date from the field. A monitoring plan was developed to analyze the performance of the pilot area wells before and after the start of the foam pilot. The injection well tubing head pressure was controlled to maintain a constant bottom hole pressure and the fluid injection rates were monitored to capture the effect of foam generation on injectivity. Inter-well tracer studies were performed to analyze the change in CO2 flow patterns in the reservoir. Production response was monitored by performing frequent well tests. The CO2 injection rate profile monitored over several WAG cycles during the course of the implementation clearly indicates the formation and propagation of foam deep into the reservoir. CO2 soluble tracer studies performed before and after the start of the foam pilot indicate significant areal diversion of CO2. The production characteristics of the four producing wells in the pilot area indicate significant mobilization of reservoir fluids attributable to CO2 diversion in the pattern. The produced gas-liquid ratio has decreased in all four of the producing wells in the pattern. Analysis of the oil production rates shows a favorable slope change with respect to pore volumes of CO2 injected. Segregation of CO2 and water close to the injection well seems to be the primary factor adversely affecting CO2 sweep efficiency in the pilot area. Foam generation leads to a gradual expansion of the gas override zone. The gradual expansion of the gas override zone seems to be the principal mechanism behind the production responses observed from the pilot area wells.
Skrettingland, K. (Statoil ASA) | Ulland, E. N. (Statoil ASA) | Ravndal, O. (Statoil ASA) | Tangen, M. (Statoil ASA) | Kristoffersen, J. B. (Statoil ASA) | Stenerud, V. R. (Statoil ASA) | Dalen, V. (Statoil ASA) | Standnes, D. C. (Statoil ASA) | Fevang, Ø. (Statoil ASA) | Mevik, K. M. (Knutsen Subsea Solutions) | McIntosh, N. (Knutsen Subsea Solutions) | Mebratu, A. (Halliburton) | Melien, I. (Halliburton) | Stavland, A. (Intl Research Inst of Stavanger)
Declining oil production and increasing water cut in mature fields highlight the need for improved conformance control. Here we report on a successful in-depth water diversion treatment using sodium silicate to increase oil recovery at the Snorre field, offshore Norway, utilizing a new operational concept of using a stimulation vessel as a platform for the large-scale injection into a subsea well. A custom modified 35,000 DWT shuttle tanker was employed for the field pilot. This paper describes the vessel preparations and the large-scale interwell silicate injection operation. The operational aspects of the large-scale interwell silicate injection include; identification of injection vessel requirements, major vessel modifications, chemical logistic, general logistics to site, major equipment set-up on vessel, subsea connection, mixing and pumping schedules, onsite QC, and real time monitoring. Experience from these operations and lessons learned are included in this paper.
After the injection of approximately 400,000 Sm3 (113,000 Sm3 preflush, followed by 240,000 Sm3 of sodium silicate gelant and 49,000 Sm3 of postflush fluid) at injection rates up to 4,000 Sm3/d, the injection from the vessel was stopped and the well was put on regular seawater injection. Following more than two years of regular production, transient pressure measurements, tracer testing and water cut data are presented from the ongoing comprehensive data acquisition program. These results demonstrate clearly the achieved in-depth flow diversion through a delayed breakthrough of injected tracers and lower water cut in the relevant production well.
Jong, Stephen (University of Texas at Austin) | Nguyen, Nhut M. (University of Texas at Austin) | Eberle, Calvin M. (University of Texas at Austin) | Nghiem, Long X. (Computer Modelling Group Ltd.) | Nguyen, Quoc P. (University of Texas at Austin)
Low Tension Gas (LTG) flooding is a novel EOR process which can address challenging reservoir conditions such as high salinity, high temperature, and tight rock. Current process understanding is limited, and a joint experimental and modeling approach allows for both interpretation and insight into the complex interactions between the key process parameters of salinity gradient, foam strength, microemulsion phase behavior, and phase desaturation in order to achieve a physically correct and predictive process model.
We performed a series of corefloods in high permeability Berea sandstones (~500 mD) to demonstrate the impact of salinity gradient on the LTG process and interactions between key mechanisms such as microemulsion phase behavior and foam stability. In order to provide additional insight into the experimental study and improve understanding of the LTG process, we used our newly developed LTG simulator which we built within CMG GEM.
The results demonstrate that decreasing slug injection salinity can lead to a 15% increase in residual oil in place (ROIP) recovery over a slug injected at optimum salinity, with earlier breakthrough and steeper recovery slope. In addition, there is evidence of a late time pressure buildup as salinity is decreased through mixing with drive salinity which is indicative of increasing foam stability. This may be due to an inverse relationship between oil-water IFT and foam stability and thus designing an optimal salinity gradient for an LTG process requires balancing oil mobilization due to ultralow IFT and effectively displacing mobilized oil with adequate foam mobility control.
We introduce and show the strength our compositional LTG simulator in a pioneering laboratory and simulation study that sheds light on the interaction between salinity, microemulsion phase behavior, and foam strength. Our conclusions indicate a significant departure from traditional ASP understanding and methodology when designing an LTG salinity gradient and serve as a foundation for future investigation.