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.
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.
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.
With the synergy of horizontal drilling and hydraulic fracturing techniques, commercial production of Unconventional Liquid Reservoirs (ULR) has been successfully demonstrated. Due to the low recovery factor of these reservoirs, it is inevitable that Enhanced Oil Recovery (EOR) will ensue. Experimental results have shown promising oil recovery potential using CO2. This study investigates oil production mechanisms from the matrix into the fracture by simulating two laboratory experiments as well as several field-scale studies, and evaluates the potential of using CO2 huff-n-puff process to enhance the oil recovery in ULR with nano-Darcy range matrix permeability in complex natural fracture networks.
This study fully explores mechanisms contributing to the oil recovery with numerical modeling of experimental work, and provides a systematic investigation of the effects of various parameters on oil recovery. The core scale modeling utilizes two methods of determining properties that are used to construct 3D heterogeneous models. The findings are then upscaled to the field scale where both simple and complex fractures in a single stage are modeled. The effects of reservoir properties and operational parameters on oil recovery are then investigated. In addition, this study is the first to present simulation results of CO2 huff-n-puff using complex fracture networks which are generated from microseismic-constraint stochastic models.
Diffusion is proven to be the dominant oil recovery mechanism at the laboratory scale. However, the field-scale reservoir simulation indicates diffusion is negligible compared to the well-known mechanisms accompanying multi-contact miscibility. This includes swelling, viscosity reduction, and gas expansion in the matrix. Overall, the CO2 huff-n-puff process was found to be beneficial in both models in terms of enhancing the ultimate oil recovery in ULR.
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.
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.
The EOR activity has been very restricted in naturally fractured reservoirs (NFR) because the fluid behavior on these reservoirs are strongly dependent of specific properties of the fractures such as direction, length, thickness, morphology and angle, and good tools were not available to get this information accurately from the reservoirs in the past. Today it is possible to get a lot of information on the fractures by using direct data sources like core samples, drill cuttings and downhole cameras; or even by indirect data sources like well log, well drilling, production history and seismic.
These advancements in the data acquisition have facilitated EOR applications and the EOR activity has increased in the past few years in NFR. GAGD is a promising technique that uses the gravitational flow to improve the sweep efficiency in the reservoir and increase oil recovery. Its benefits have been proven in some academic works and in field applications, such as the Cantarell Oil field that achieved outstanding results.
In this work, we have developed an experimental model that simulates the flow behavior of NFR from a Brazilian offshore oilfield. The model uses rectangular Berea Sandstones blocks that simulate the matrix rock in the experiments and these blocks are separated by small gaps using metal spacers. These gaps act as the fractures in the experimental model. The experimental conditions are close to the reservoir and the used configuration simulates the interaction between matrix and fracture, as well as the flow in the fractures.
In the experiments the blocks are packed in a high-pressure physical model in the desired configuration. The gas is injected from the top and the oil is produced from the bottom. This work investigated the influence of the gas injection rate on oil production. The experiments were history matched using the commercial numerical simulator GEM from CMG.
The experimental results showed good oil recovery performance with recovery factor as high as 40 per cent of OOIP, and it was observed that this value increases when higher gas rates are used. The numerical simulator has some limitations but provided a good history match with the results of the experiments.
This paper proves the efficiency of the CO2 injection in NFR and also presents a new procedure for experimental modeling of fractured systems.
The goal of this research is to improve oil recovery by reducing bypassing due to fractures, common in carbonate reservoirs. Salinity sensitive polymeric particles (SSPP) are synthesized in this study, which can plug fractures in reservoir rocks and divert fluid flow into the matrix. SSPP swell in brine; the swelling is a function of brine salinity. SSPP expand many times (~70 times) in DI water, but swell only about 3 times in very high salinity (20 wt% NaCl) brine. The swelling of the particles is independent of pH in the range of 2 to 12.6. The swelling process is reversible with salinity. These particles are stable at 60 °C for at least several months. Core flood results show that these small particles can be transported through fractures during high salinity brine injection and plug the fractures during low salinity brine injection. Then the injectant fluid flow is diverted into the matrix and recovers oil from previously unswept matrix. SSPP injection increases waterflood recovery in cores with full fractures and half fracture connected to the inlet. The SSPP placement also increases oil recovery for tertiary miscible floods.
Foamed fluids with the gas phase of carbon dioxide (CO2) have been applied as fracturing fluids to develop unconventional resources. This type of fracturing fluids meets the waterless requirements by unconventional reservoirs, which are prone to damage by clay swelling and blocking pore throat in water environment. Conventional CO2 foams with surfactants have low durability under high temperature and high salinity, which limit their application. Nanoparticles provide a new technique to stabilize CO2 foams under harsh reservoir conditions. It's essential to determine in-situ rheology of CO2 foams stabilized by nanoparticles in order to predict proppant transport in reservoir fractures and improve oil production.
The shear viscosity and foam texture of non-Newtonian fluids under reservoir conditions are critical to transport proppant and generate effective micro-channels. This study determined the in-situ shear viscosity of supercritical CO2 foams stabilized by nano-SiO2 in the Flow Loop apparatus with shear rates of 5950~17850 s-1 at the pressure of 1140±20 psig and the temperature of 40 °C. Supercritical CO2 with the density of 0.2~0.4 g/ml and the viscosity of 0.02~0.04 cp under typical reservoir conditions were applied to generate foams. The foams were tested with high foam quality up to 80% to minimize the usage of water. The effects of shear rates, salinity, surfactant, and nanoparticle sizes and on the rheology of gas foams with different foam qualities were experimentally investigated. The foam texture and stability were observed through an in-line sapphire tube. Further, proppant transport by CO2 foams and the placement in fractures were analyzed by considering the rheology of non-Newtonian fluids and the mechanisms of gravity driven settling and hindered settling/slurry flow.
The conditions of nanoparticle foaming systems were optimized through orthogonal experimental design. The dense and stable foams were generated and observed under high pressure and elevated temperature conditions. It was observed that CO2 foams with high quality of 80% demonstrated the highest viscosity and stability under optimal conditions. The foams with nanoparticles demonstrated both shear- thinning and shear-thickening behaviors depending on foam quality and components. The salinity and nanoparticle size affect foam rheology in two ways depending on components, foam quality, and shear rates.
While the viscosities of CO2 foam stabilized by nanoparticles have been widely studied recently, no work has been done to observe the stability and texture of supercritical CO2 foam after shearing under high pressure and high temperature, not to mention proppant transport by CO2 foam. This study provided a pioneering insight to the proppant transport by viscous supercritical CO2 foam stabilized by nanoparticles.
There is considerable and timely interest in oil and condensate production from liquid-rich regions, placing emphasis on the ability to predict the behavior of gas condensate bank developments and saturation dynamics in shale gas reservoirs. As the pressure in the near-wellbore region drops below the dew-point, liquid droplets are formed and tend to be trapped in small pores. It has been suggested that the injection of CO2 into shale gas reservoirs can be a feasible option to enhance recovery of natural gas and valuable condensate oil, while at the same time sequestering CO2 underground. This work develops simulation capabilities to understand and predict complex transport processes and phase behavior in these reservoirs for efficient and environmentally friendly production management.
Although liquid-rich shale plays are economically producible, existing simulation techniques fail to include many of the production phenomena associated with the fluid system that consists of multiple gas species or phases. In this work, we develop a multicomponent compositional simulator for the modeling of gas-condensate shale reservoirs with complex fracture systems. Related storage and transport mechanisms such as multicomponent apparent permeability (MAP), sorption and molecular diffusion are considered. In order to accurately capture the complicated phase behavior of the multiphase fluids, an equation of State (EOS) based phase package is incorporated into the simulator. Due to the large capillary pressure that exists in the nanopores of ultra-tight shale matrix, the phase package considers the effect of capillary pressure on phase equilibrium calculations. A modified negative-flash algorithm that combines Newton's method and successive substitution iteration (SSI) is used for phase stability analysis under the effect of capillary pressure between oil and gas phases.
In addition, a lower-dimensional discrete fracture and matrix (DFM) model is implemented. The DFM model is based on unstructured gridding, and can accurately and efficiently handle the non-ideal geometries of hydraulic fracture in stimulated unconventional formation. Optimized local grid refinement (LGR) is employed to capture the extremely sharp potential gradient and saturation dynamics in the ultra-tight matrix around fracture.
We apply the developed simulator to study the combined effects of capillary pressure and multicomponent storage and transport mechanisms that are closely associated with the phase behavior and hydrocarbon recovery in gas-condensate shale reservoirs. We present preliminary simulation studies to show the applicability of CO2 huff-n-puff for the purpose of enhanced hydrocarbons recovery. Several design components such as the number of cycles and the length of injection period in the huff-n-puff process are also briefly investigated.