Fortenberry, R. (Ultimate EOR Services) | Delshad, M. (Ultimate EOR Services) | Suniga, P. (Ultimate EOR Services) | Koyassan Veedu, F. (DeGolyer & MacNaughton) | Wang, P. (DeGolyer & MacNaughton) | Al-Kaaoud, H. (Kuwait Oil Company) | Singh, B. B. (Kuwait Oil Company) | Tiwari, S. (Kuwait Oil Company) | Baroon, B. (Kuwait Oil Company) | Pope, G. A. (University of Texas at Austin)
Our team has developed a new simulation model for an upcoming 5-spot Alkaline-Surfactant-Polymer (ASP) pilot in the Sabriyah Mauddud reservoir in Kuwait. We present new pilot simulation results based on new data from pilot wells and an updated geocelluar reservoir model. New cores and well logs were used to update the geocellular model, including initial fluid distributions, permeability and layer flow allocation.
From the updated geocellular model a smaller dynamic sector model was extracted to history match field performance of a waterflood pattern. From the dynamic model a yet smaller pilot model was extracted and refined to simulate the 5-spot ASP pilot.
We used this pilot model to evaluate injection composition, zonal completions, observation well locations, interwell tracer test design and predicted performance of ASP flooding. A sensitivity analysis for some important design variables and pilot performance benchmarks is also included. We used multiple interwell tracer test simulations to estimate reservoir sweep efficiency for both water and ASP fluids, and to help us understand how well operations will affect this unconfined ASP pilot. This work details some crucial aspects of pre-ASP pilot design and implementation.
Thrasher, David (BP Exploration) | Nottingham, Derek (BP Exploration (Alaska) Inc.) | Stechauner, Bernhard (BP Exploration (Alaska) Inc.) | Ohms, Danielle (BP Exploration (Alaska) Inc.) | Stechauner, Gerda (BP Exploration (Alaska) Inc.) | Singh, Praveen K. (BP America Inc.) | Angarita, Monica Lara (BP Exploration)
Waterflood conformance control due to reservoir heterogeneity is a common challenge to many oilfield developments. This paper describes the application at-scale of a thermally-activated polymer particle system (TAP) for improving waterflood sweep efficiency in the Prudhoe Bay field, Alaska. Since 2004, the technology has been successfully deployed 91 times in Prudhoe Bay Unit on the North Slope of Alaska as part of an approved Enhanced Oil Recovery (EOR) program. A total of 1.6 million gallons of chemical polymer particles have been injected into approximately half of the available waterflood patterns.
Once the polymer particles activate deep in the reservoir, they provide resistance to water flow in the thief (swept) zones. The treatment design workflow applies a thermal model which accounts for the impact of the temperature distribution in the reservoir on activation of the polymer particles. Challenges associated with performance evaluation of the treatment program in a normal operational setting (as opposed to field trial) have been addressed, particularly in relation to interferences to interpretation resulting from the ongoing application of miscible gas EOR in the waterflood areas.
Of the 44 treatments deployed between 2008 and 2012, 22 were sufficiently mature to have performance data which was not adversely impacted by interferences from well work, changes to operating conditions, or miscible gas breakthrough. So far, only one of the 22 patterns has not indicated an incremental oil response, while in two patterns the response had started too recently to be able to extrapolate the overall response magnitude. The analysis showed overall positive responses from the treatments that are competitive with other well work on cost/bbl and project economics. Results from this study provide insights on key controls on waterflood sweep improvements, and inform future candidate selection and optimization of treatment designs.
The production performance analysis was corroborated by wellhead injectivity, repeat pressure fall-off tests, and reservoir modeling. This paper documents a good case history of waterflood sweep improvement.
When compared with steam-assisted gravity drainage (SAGD) operations in the McMurray Formation, Athabasca Oil Sands, SAGD projects in the Clearwater Formation at Cold Lake did not perform as expected, likely because of reservoir properties. This paper will use the Orion SAGD case study to: (1) investigate the impacts of reservoir properties on the SAGD thermal efficiency by field evidences; (2) identify key geological parameters influencing each well pad; and (3) summarize major geological challenges for Orion SAGD expansion.
Wireline log data were interpreted to characterize reservoir properties, which were used to build 3D models. 3D visualizations and 2D cross sections of the reservoir revealed spatial distribution and heterogeneity of each property. SAGD production performance was analyzed using: (1) temperature profiles that monitored the growth of the steam chamber; (2) cumulative steam-oil ratios (CSORs); and (3) oil production rates (OPRates), which are direct indicators of thermal efficiency.
Results show that impermeable barriers and low-permeability zones were detrimental to steam injectivity and steam chamber growth, as observation wells in Pilot Pads 1 and 3 did not detect any steam saturation. High-permeability zones favored high steam injectivity and mobility, especially in Pad 105. Steam chambers were irregularly shaped by high shale-content zones, as two sharp spikes displayed on the temperature profile in Pad 103. Low oil-saturation zones and thin net-pays increased the CSORs, as seen in Pads 106 and 104. Impermeable barriers are almost horizontal, making no difference on well pad orientation by their dip angles. Lack of porosity variation made it difficult to identify the impact of porosity on each well pad.
The relatively extensive distribution of impermeable barriers between and above well pairs, as well as the relatively large area of low oil saturation and thin net-pay, were identified as major geological challenges.
As one of the unconventional resources, tight oil has become one of the most important contributor of oil reserves and production growth. The successful commercial production of tight oil is mainly reliant on the advancement in horizontal drilling and multistage hydraulic fracturing technique. Development of tight oil reservoirs remains in an early stage. Primary oil recovery factor in these reservoirs is very low, leaving substantial volume of oil trapped underground due to the low porosity, low permeability characteristic of tight oil reservoirs. Thus, investigation of enhanced oil recovery methods is more than imperative in tight oil reservoirs. CO2 Huff-and-Puff technology has been effectively applied in conventional reservoirs and can be tailored to adapt for the characteristics of tight oil reservoirs.
In this study, the performance of water flooding in tight oil reservoir is studied and compared with that of the CO2 Huff-and-Puff process. Sensitivity analysis demonstrates that the performance of CO2 Huff-and-Puff is more sensitive to the length of gas injection and production step in each cycle, compared to the soaking time. The CO2 Huff-and-Puff process is optimized and an adaptive CO2 Huff-and-Puff process is conducted for tight oil reservoirs after primary production. Simulation results show that the adaptive cycle length CO2 Huff-and-Puff process can improve the incremental oil recovery by 11.1% over a fixed cycle length process. Finally, the inter-well interference during CO2 Huff-and-Puff is studied, and it is found that a multi-well asynchronous CO2 Huff-and-Puff pattern can improve the incremental oil recovery by 31.6% over that of a synchronous pattern.
Barnes, J. R (Shell Global Solutions International B.V.) | Regalado, D. Perez (Shell Global Solutions International B.V.) | Doll, M. J. (Shell Global Solutions (US) Inc.) | King, T. E. (Shell Global Solutions (US) Inc.) | Pretzer, L. E. (Shell Global Solutions (US) Inc.) | Semple, T. C. (Shell Global Solutions (US) Inc.)
Surfactant flooding is an enhanced oil recovery (EOR) technique that involves the injection of an aqueous solution of surfactant (and, optionally, alkaline and polymer) into an oil reservoir to mobilise and produce the remaining oil. The quantities of surfactants needed for pilots and future commercial scale projects are large (100s to 10,000s of tons) and necessitate large scale manufacture using existing processes and plants for the different manufacturing steps. Upscaling of surfactants requires a rigorous QA/QC process to control and ensure the quality of batches of surfactants produced. Case studies are described from the perspective of a surfactant manufacturer where 800 and 6000 ton of surfactant were manufactured (as 60% and 20% active concentrates respectively) for two multi spot pilots. These case studies illustrate: The need to define the laboratory tests for surfactant composition and performance. Plus associated repeatability data and specifications (minimum and maximum values) for clear, unambiguous decisions. How the QC is checked at each stage in manufacture from the initial feedstock, through various stages, to the final delivered surfactant concentrate/blend. This also applies to the scale-up procedure from the laboratory made scale (kg) to pilot scale (100s of kg) to the pilot/commercial scale (100s to 1000s of tons). Novel correlations between composition and performance (e.g. optimal salinity, via oil/water phase behaviour tests), developed during the surfactant pilot scale manufacture stage, to a) put more emphasis on verifying batch consistency with faster, easier to use composition tests, and b) give more assurance that large scale production gives the expected sub-surface performance. This requires R&D over an extended time, ahead of large scale manufacture.
The need to define the laboratory tests for surfactant composition and performance. Plus associated repeatability data and specifications (minimum and maximum values) for clear, unambiguous decisions.
How the QC is checked at each stage in manufacture from the initial feedstock, through various stages, to the final delivered surfactant concentrate/blend. This also applies to the scale-up procedure from the laboratory made scale (kg) to pilot scale (100s of kg) to the pilot/commercial scale (100s to 1000s of tons).
Novel correlations between composition and performance (e.g. optimal salinity, via oil/water phase behaviour tests), developed during the surfactant pilot scale manufacture stage, to a) put more emphasis on verifying batch consistency with faster, easier to use composition tests, and b) give more assurance that large scale production gives the expected sub-surface performance. This requires R&D over an extended time, ahead of large scale manufacture.
Overall, the paper shows that industrial scale production of surfactants for chemical EOR is feasible and goes through the essential steps to achieve this. Control of large scale batch quality and performance is critical.
This paper also shows results for improved, highly active (60%+) surfactants concentrates with improved rheology behaviour which will be easier to pump, mix and dilute at the facilities than earlier products. This helps to reduce logistical costs thereby improving project economics.
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.
Post-fracturing production data analysis indicates stimulation of some west Texas wells with surfactant additives did not enhance production as high as expected. Analysis of flowback and produced water for surfactant residues revealed 99% of surfactant was retained inside wells (
Literature precedent exists that polyelectrolyte (PET)-based SAs could significantly reduce surfactant adsorption not only onto a variety of outcrop minerals (Carlpool dolomite, calcite, kaolinite, Berea sandstone, Indiana limestone, etc.) and metal oxide nanoparticles, but also unconventional shale formulations in which surface area can be up to 700 m2/g. In this study, the adsorptions of surfactant and SA to proppants were first examined. Results indicate no adsorption was observed to proppant for both surfactants and PET-based SAs. SAs (0.5 to 1 gal/1,000 gal (gpt)) were then injected with surfactant (1 to 3 gpt) at an appropriate ratio into column-packed shale formulations (primarily composed of calcite, dolomite, quartz, illite, pyrite, and plagioclase feldspar) to investigate its effectiveness in controlling surfactant retention caused by adsorption. Laboratory testing revealed injection of 3 gpt mixture of surfactant and SA has a similar adsorption profile (surface tension as a function of time) as 3 gpt surfactant alone based on the dynamic surface tension measurement. Notably, the addition of SAs resulted in lower surface tension and enhanced hydrocarbon solubility; and thus, an improved oil recovery by surfactant was achieved as evidenced by the oil recovery tests. Additionally, 68% friction reduction of the fracturing fluid with surfactant and SA was sufficient for the field operation compared to the guar-based fluid used in the hydraulic fracturing applications.
As a result of the laboratory findings, field trials were executed on a three well pad in the Permian basin (PB). For the first 30 days oil and gas production appeared to be significantly higher than the average production from offset wells in the same area that were previously fractured with the same surfactant.
Pilots are widely used for the purpose of gathering valuable information about performance and practical challenges of implementing a particular CEOR process in a given field (
Addition of chemical species to the material balance equations alongside finer resolution requirements for CEOR simulations compared to waterfloods (WF), often make it impractical to run full field CEOR simulations to the required accuracy. Massively parallel computing, dynamic local grid refinement and sector modeling have been used with varying success, of which sector modeling is the most common. Sector models, by their very definition, are also naturally suited for modeling of pilots.
The art of sector modeling needs mastering a few important steps such as: appropriate selection of the sector model extent, details on carving it out of the Full Field Model (FFM), populating it with proper petrophysical and fluid properties, initializing it to correct initial conditions and optimizing its boundary conditions. On top of that, choice of optimum grid size for proper trade-off of simulation run times and accuracy needs to be considered.
This paper presents a case study for appropriate simulation of a CEOR pilot within Chevron. The candidate has a waterflood history matched FFM. This model is used to generate a sector model for the CEOR pilot area. This paper outlines how the extent of the sector model and all the regions in communication with the Area of Interest (AOI) is decided. It also discusses proper initialization and optimization of the boundary conditions of the sector model along with its appropriate refinement and grid optimization. Proper CEOR simulations on the final optimized sector model and sensitivity analysis are also presented. The challenges, lessons learned and best practices are shared and important considerations for adequate simulation of CEOR processes are outlined.
Scaling up from lab to pilot is one of the challenges to meet in any ASP project to accomplish the requirements at full implementation. Tailored EOR surfactants developed and manufactured in the laboratory, to achieve the lowest interfacial tension (IFT) between oil and water at the reservoir conditions, have to be viable and robust in the manufacture, capable in performance and compatible in the formulation, not only at laboratory scale, but also at industrial scale.
It is described in this poster the route map in the development and manufacture of alkyl aryl sulfonates surfactants for the Cepsa ASP pilot project in the Caracara Sur field, Los Llanos basin (Colombia) from a continuous feed-back of the laboratory tests. The surfactant employed for the project was selected from other surfactants from several suppliers and dyalkylbenzene sodium sulfonate was the one achieving the lowest interfacial tension for Caracara field conditions. The dyalkylbenzene sodium sulfonate was accompanied by a co-surfactant improving the solubility and performance properties.
Pilot ASP injection started in May 2015 and some conclusions were obtained during the production of the surfactants in several manufacture batches: Composition, molecular weight even isomerism of alkylbenzenes may impact strongly on the interfacial activity of alkyl aryl sulfonates surfactants. Sulfonation and neutralization of alkylbenzenes are critical processes to comply the requirements of alkyl aryl surfactants for any cEOR project. Finally, the laboratory in the field for quality assurance and quality control (QA/QC) of surfactants is completely necessary. Periodical sampling and on-site analyses are scheduled but also samples delivery to research center for more sophisticated analyses. These data are essential for the final performance evaluation and the project success.
Composition, molecular weight even isomerism of alkylbenzenes may impact strongly on the interfacial activity of alkyl aryl sulfonates surfactants.
Sulfonation and neutralization of alkylbenzenes are critical processes to comply the requirements of alkyl aryl surfactants for any cEOR project.
Finally, the laboratory in the field for quality assurance and quality control (QA/QC) of surfactants is completely necessary. Periodical sampling and on-site analyses are scheduled but also samples delivery to research center for more sophisticated analyses. These data are essential for the final performance evaluation and the project success.
Use of foams to control CO2 floods conformance is attracting a renewed interest in recent years due its flexibility and ease of application. This application becomes even more attractive in current times of low oil price, as it can be an inexpensive mean to maximize CO2 utilization efficiency and increase production at no capital expenses. However, it is generally recognized that to maximize chances of success of a pilot application, an appropriate foaming formulation must be designed for a given reservoir and characterized in petrophysics lab. This usually requires an extensive laboratory work that is not always compatible with cost constraints.
We present a new cost-effective workflow that focuses on evaluating two formulation performance indicators derived from the population balance model: foam creation (related to foaming power) and resistance to foam destruction (related to foam stabilization against coarsening and coalescence).
We assess these two parameters in representative reservoir conditions by measuring foam mobility reduction in porous media and foam lifetimes. Experimental results and simple scaling arguments show that these two measurements, both of importance to the application, are mostly independent. This shed light on a recurring question pertaining to the relevance of bulk foam experiments to predict foam efficiency in porous media. With this in mind, we present a new approach for measuring mobility reduction in porous media with a higher throughput than usual corefloods experiments. This methodology is based on sandpack experiments as well as serial coreflood experiments that allow multiple successive formulations testing. We show that the link between sandpack and coreflood results is far from being straightforward, and depends on static (geometrical) as well as dynamic (flow) parameters.
Overall, this work provides new insights on the major performance indicators used to evaluate foam efficiency for gas conformance control in oil reservoirs. We build on this understanding to present a novel approach that can help developing more efficient foam EOR solutions. In particular, it allows tailoring foaming agents properties (such as foaminess and foam stabilization) to specific conditions of a given application (oil saturation, vertical heterogeneity, etc…).