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Results
Abstract Due to advances in computer technology, geo-scientists are increasingly able to build reservoir models which can incorporate significant geological details. It is not unusual to find geological models which contain millions of cells. Flow simulating such models is still a challenge as running a typical simulation model takes two orders of magnitude more time than generating a geological model. Upgridding the geological model to reduce the number of grid blocks while maintaining the essential heterogeneity details to preserve the dynamic performance is the only solution to this problem. In the literature, many solutions are proposed to upgrid the geological model. The simple static solutions involve combining layers with similar static properties so that the heterogeneous details are preserved. In our paper, we take the method one step further. It has been observed in the past that upgridding should be dependent on the flow process. That is, the way the layers are combined would be different for depletion drive compared to water flooding. The displacement of fluids is strongly dependent on the type of drive; hence, rearrangement of the fine scale layers has to be different to capture this behavior. In our approach, we propose a method of upgridding which can be applied for either secondary or tertiary recovery processes. Our method is analytical and is based on an idea that fractional flow of a fine scale model has to be preserved on a coarse scale. We use fractional flow on a fine scale model and define our error as the difference between fractional flows of a coarse scale vs. fine scale. We combine layers which minimizes this difference. Using our procedure, we demonstrate that for favorable mobility ratio, it is better that we isolate low permeability layers; whereas, for adverse mobility ratio, we need to isolate high permeability layers. Using both synthetic and field cases, we demonstrate that our proposed method provides superior upgridding compared to other methods currently available in the literature.
- Asia (0.68)
- North America > United States > Texas (0.46)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Abstract Results of Newtonian Fluids flooding very homogeneous porous media show that the Displacement Efficiency (ED) of a certain system is determined by the Capillary Number (Nc) of the driving fluid. The experience gained from Chemical Flooding natural cores and reservoirs that are all micro (pore scale) heterogeneous to some degree show that ED is influenced, besides Nc, by many other factors as explained below. Newtonian Fluids do not have elastic properties; emulsions and gas bubbles are not formed; when flooding, there is no change in the wettability of the system; there is no imbibition; and there is no alteration in the geometry of the pores. However, when chemical flooding, elasticity markedly effects the ED; emulsions and gas bubbles (especially when gas is injected) will often show up, which from core and field tests, could significantly increase the recovery; both w/o and o/w emulsions markedly change the phase permeability behavior and water cut; the wettability will often change and imbibition will occur; pore geometry alteration by solution and precipitation will happen, which influences the permeability, imbibition and recovery. The above factors all markedly influence the ED of the system, especially when many factors act jointly. From the above understanding, some directions on the development and selection of chemicals for EOR are put forward. The concept of ultimate ED and economic ED and its affect on the selection of actual field flooding systems is analyzed (many papers analyze ultimate ED, however, in the field, usually economical ED is more important). Besides Nc, the above factors should be considered when developing and selection chemicals and flooding systems. The above insights can further deepen our knowledge of the mechanism of chemical flooding, promote further research in this area and form better selection criteria for EOR chemicals and flooding systems in the field.
- North America (0.68)
- Asia > China > Heilongjiang Province (0.30)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- North America > United States > Louisiana > China Field (0.98)
Abstract A thorough understanding of foam fundamentals is crucial to the optimum design of foams for improved/enhanced oil recovery. This study, for the first time, presents anomalous foam fractional flow solutions which deviate significantly from the conventional solutions at high injection foam qualities, by comparig Method of Characteristics and mechanistic bubble-population-balance simulations. The results from modeling and simulations based on coreflood experiments revealed that (1) there exist three regions: region "A" with relatively wet (or high fw) injection conditions where the solutions are consistent with the conventional fractional flow theory; region "C" with very dry (or low fw) injection conditions where the solutions deviate significantly; and region "B" in between which has a negative dfw/dSw slope showing physically unstable solutions; (2) for dry injection conditions in region "C", the solutions require a constant state (IJ) between initial (I) and injection (J) conditions, forcing a shock from I to IJ by intersecting fractional flow curves, followed by spreading waves or another shock to reach from IJ to J; and (3) the location of IJ in fw vs. Sw domain moves to the left (or toward lower Sw) as the total injection velocity increases for both weak and strong foams until it reaches limiting water saturation. Even though foams at high injection quality are popular for mobility control associating a minimal amount of surfactant solutions, foam behaviors at dry conditions have not been thoroughly investigated and understood. The outcome of this study is believe to be helpful to successful planning of foam field I/EOR applications.
- North America > United States > California > Sunset Field (0.99)
- North America > United States > California > San Joaquin Basin > Midway-Sunset Field > Webster Formation (0.99)
- North America > United States > California > San Joaquin Basin > Midway-Sunset Field > Monterey Formation (0.99)
- (13 more...)
Abstract Numerous core-flooding experiments have shown that Low-Salinity Water Flooding (LSWF) could improve oil recovery in sandstone reservoirs. However, LSWF recovery mechanisms remain highly contentious primarily because of the absence of crucial boundary conditions. The objective of this paper is to conduct a parametric study using statistical analysis and simulation to measure the sensitivities of LSWF recovery mechanisms in sandstone reservoirs. The summary of 411 coreflooding experiments discussed in this paper highlights the extent and consistency in reporting boundary conditions, which has two implications for statistical analysis: (1) Even though statistical correlations of the residual oil saturation to chlorite (0.7891) and kaolinite (0.4399) contents, as well as the wettability index (0.3890), are comparably strong, the majority of dataset entries are missing, and a prediction model cannot be generated; (2) If a prediction model is generated without clay content values and a wettability index, even though LSWF emphasizes wettability modification by virtue of oil aging time and the strong influence of brine cation and divalent ion concentrations on Sor, the prediction model's regression curve and confidence level are poor. Reservoir simulations conducted to examine LSWF recovery sensitivities conclude that LSWF recovery mechanisms are governed based on the initial and final wetting states. In strong water-wet conditions, the increase in oil relative permeability is the underlying recovery mechanism. In weak water-wet conditions, the incremental recovery of LSWF is driven by low capillary pressures. In weak oil-wet conditions, the primary LSWF recovery mechanism is the increase in oil relative permeability, and the secondary mechanism is the change of the non-wetting phase to oil. In strong oil-wet conditions, the underlining LSWF recovery mechanism is the increase in oil relative permeability. In all cases, an appreciable decrease in interfacial tension (IFT) is realized at the breakthrough recovery however that is rapidly overshadowed by the increase in oil relative permeability and decrease in contact angle.
- Europe (1.00)
- Asia > Middle East (1.00)
- North America > United States > Texas (0.68)
- North America > United States > California (0.68)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > PL 102 > Block 25/5 > NOAKA Project > Frøy Field > Brent Group Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > PL 102 > Block 25/2 > NOAKA Project > Frøy Field > Brent Group Formation (0.99)
- (2 more...)
Abstract This work investigates dehydration of polymer gel by capillary imbibition of water bound in gel into a strongly water-wet matrix. Polymer gel is a cross linked polymer solution of high water content, where water can leave the gel and propagate through porous media, whereas the large 3D polymer gel structures cannot. In fractured reservoirs, polymer gel can be used for conformance control by reducing fracture conductivity. Dehydration of polymer gel by spontaneous imbibition contributes to shrinkage of the gel, which may open parts of the initially gel filled fracture to flow and significantly reduce the pressure resistance of the gel treatment. Spontaneous imbibition of water bound in aged Cr(III)-Acetate-HPAM gel was observed and quantified. Oil saturated chalk core plugs were submerged in gel and the rate of spontaneous imbibition was measured. Two boundary conditions were tested; 1) all faces open (AFO) and 2) two ends open-oil-water (TEO-OW), where one end was in contact with the imbibing fluid (gel or brine) and the other was in contact with oil. The rate of spontaneous imbibition was significantly slower in gel compared to brine, and was highly sensitive to the ratio between matrix volume and surface open to flow, decreasing with increasing ratios. The presence of a dehydrated gel layer on the core surface lowered the rate of imbibition; continuous loss of water to the core increased the gel layer concentration and thus the barrier to flow between the core and fresh gel. Severe gel dehydration and shrinkage up to 99 % was observed in the experiments, suggesting that gel treatments may lose efficiency over time in field applications where spontaneous imbibition is a contributing recovery mechanism. The implications of gel dehydration by spontaneous imbibition, and its relevance in field applications, are discussed for both gel and gelant field treatments.
- Europe (1.00)
- North America > United States > Oklahoma (0.28)
- North America > United States > Texas (0.28)
- Research Report > Experimental Study (1.00)
- Research Report > New Finding (0.87)
Abstract Water- Alternating- Gas (WAG) injection in waterflooded reservoirs can increase oil recovery and extend the life of these reservoirs. Reliable reservoir simulations are needed to predict the performance of WAG injection before field implementation. This requires accurate sets of relative permeability (kr) and capillary pressure (Pc) functions for each fluid phase, in a three-phase flow regime. The WAG process also involves another major complication, hysteresis, which is caused by flow reversal happening during WAG injection. Hysteresis is one of the most phenomena manipulating the performance of WAG injection and hence, it has to be carefully accounted for. In this study we have benefited from the results of a series of coreflood experiments that we have been running since 1997 as a part of the Characterization of Three-Phase Flow and WAG Injection JIP (joint industry project) at Heriot-Watt University. In particular we focus on a WAG experiment carried out on a water wet core to obtain three-phase relative permeability values for oil, water and gas. The relative permeabilities exhibit significant and irreversible hysteresis for, oil, water and gas. The observed hysteresis, which is due to the cyclic injection of water and gas during the experiment, is not predicted by the existing hysteresis models. We present a new three-phase relative permeability model coupled with hysteresis effect for modelling of the observed cycle- dependent relative permeabilities taking place during WAG injection. The approach was successfully tested and verified using the measured three-phase relative permeability values obtained from WAG experiment. In line with our laboratory observations, the new model predicts the reduction of the gas mobility during consecutive water and gas injection cycles as well as the increase in oil relative permeability happening in consecutive water injection cycles.
- Europe (1.00)
- North America > United States (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.38)
Abstract In March 2008 Petro Andina Resources implemented the first polymer gel treatment in an unconsolidated sandstone reservoir in Argentina's northern Patagonia. The project was implemented in the Jagüel Casa de Piedra and El Corcobo Norte fields, located in the Neuquen basin. Oil production began in November 2004 followed by water injection project approximately one year later for pressure support. However, sand production and the generation of wormholes resulted in severe water channeling detrimenting volumetric efficiency. Tracer studies confirmed rapid transit times between injector and offset producers in patterns with an average well spacing of 280 meters. The first conformance pilot occurred in 2008 with a non-conventional polymer injection procedure that included a series of small volume, high concentration gel slugs followed by a short shut-in period. The objective of this strategy was to allow the gelation reaction to occur before reaching the offset producing wells. Successive gel slugs were placed behind the initial gel injection in order to block a significant volume of the highest permeability wormholes. Extensive diagnostics were applied before and after the initial polymer gel treatment, including tracers, monitoring of injection pressure and analysis of fluid production data. Based on a sustained WOR reduction from 6 to 1 in the pilot project after approximately one year, nine additional conformance gel treatments were implemented as of May 2011. The treatment designs were modified in successive projects based on lessons learned during preceding conformance campaigns. One of the major challenges was to reduce the incidence and consequences of gel breakthrough in offset producing wells. The paper will discuss the reservoir diagnostics that led to the selection of polymer gel as a method used to mitigate severe water channeling in this unconsolidated sandstone reservoir and the evolution of the conformance strategies applied in subsequent treatments from 2009 to 2011.
- South America > Argentina > Mendoza Province (0.70)
- South America > Argentina > Neuquén Province > Neuquén (0.55)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.35)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (3 more...)
Improved Reservoir Characterization using Petrophysical Classifiers within Electrofacies
Teh, Woan Jing (Department of Chemical and Petroleum Engineering, University of Kansas) | Willhite, G Paul (Department of Chemical and Petroleum Engineering, University of Kansas) | Doveton, John H. (Kansas Geological Survey)
Abstract Estimation of permeability in a reservoir is necessary for simulation of production history. In mature fields, cores are limited so estimation of permeability is usually done from permeability-porosity correlations developed from cored wells. In this paper, a methodology is presented to predict permeability from well logs. The method groups the well logs into electrofacies, which are recognized to correspond with core lithofacies. The permeability-porosity correlations in the core data are developed using petrophysical classifiers - rock fabric number, rfn for dolomite and flow zone indicator, FZI for sandstone. The rfn and FZI are calculated for the cored wells and calibrated to the well log measurements within each electrofacies. The petrophysical classifiers extract the pore connectivity information from the well logs within each electrofacies, representing similar lithology. The permeability is then calculated from the porosity, using the petrophysical classifier values. Application of the methodology is demonstrated for dolomite and sandstone intervals in the Ogallah Field, Kansas. Permeabilities obtained from this approach closely matched core measurements.
- North America > United States > Texas (0.28)
- North America > United States > Kansas (0.25)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.75)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.50)
- South America > Ecuador > Oriente Basin (0.99)
- North America > United States > Kansas (0.91)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Uncertainty (0.68)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning > Clustering (0.48)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning > Regression (0.46)
Abstract New technology in horizontal drilling and stimulation has caused production from ultra-tight oil formations to increase rapidly over the last decade. While initial rates are high, recovery factors for these types of reservoirs are predicted to be low, around 5–10%. Unlike conventional reservoirs, water flooding does not appear to be a viable secondary option due to its low injectivity. Recent analysis has shown that gas injection may be an effective alternative. A 4-section area of the Elm Coulee field in eastern Montana is used to study the impact of different gas injection schemes: carbon dioxide, immiscible hydrocarbon and miscible hydrocarbon. This paper examines the difference in total recovery, production rate and efficiency using a flow simulation model. Recovery efficiency is similar for both miscible hydrocarbon gases and carbon dioxide with recoveries increasing from 6% on primary production to around 20% with gas injection. While the increased recovery is encouraging, both methods have some practical limitations. Carbon dioxide is currently unavailable in many basins, and while hydrocarbon gases are available in most oil fields, they are rarely used as injectants because they are marketable. We performed a cost-benefit analysis of selling the hydrocarbon gas versus using it to increase oil production. We assumed a $10 million investment in compression and facilities for the 4-section area, and used a $5/mscf cost for the gas and $80/stb revenue for the oil. The net present value for these criteria in this area is $68 million and the rate of return is 83%. The value of this work is that it demonstrates that injecting gas (both immiscible and especially miscible) will appreciably increase oil recovery in very low permeability reservoirs. These types of reservoirs are becoming more prevalent, and a large prize is available to those who find ways to increase recovery from them. In the case of hydrocarbon gas, the economics appear to be favorable for current commodity prices.
- North America > United States > North Dakota > Mountrail County (0.26)
- North America > United States > Montana > Richland County (0.26)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.55)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.52)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.47)
Abstract The primary purpose of using surfactants in stimulating hydrocarbon rich gas reservoirs is to reduce interfacial tension, and/or modify contact angle and reservoir wettability. However, many surfactants either adsorb rapidly within the first few inches of the formation, or negatively impact reservoir wettability, thus reducing their effectiveness in lowering capillary pressure. These phenomena can result in phase trapping of the injected fluid adversely impacting oil and gas production. This study describes experimental and field studies comparing various common surfactants used in oil bearing formations including alcohol ethoxylates, EO-PO block copolymers, ethoxylated amines and a multi-phase complex nano fluid system to determine their impact on oil recovery and adsorption tendencies when injected through 5-foot and 1 ft sand columns. Ammot cell tests were used to evaluate imbibition of oil and water and a core flow apparatus was used to evaluate regained relative permeabilities. The results are correlated with surface energies of actual formation materials, oils and treating fluids. The results are used to select formulations containing surfactant, solvents and co-solvents to apply within the fracturing fluid to decrease adsorption, eliminate post treatment emulsions and improve oil and gas recovery in hydrocarbon rich gas wells.
- North America > Canada (0.69)
- North America > United States > Texas (0.46)
- North America > United States > West Virginia (0.28)
- (2 more...)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > West Virginia > Appalachian Basin > Utica Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- (11 more...)