Cumulative Oil Production Research Articles

Effect of temperature on two-phase gas/oil relative permeability in unconsolidated sands

Thermal Enhanced Oil Recovery (TEOR) for heavy oil reservoirs involves the simultaneous flow of oil and steam, mimicking the gaseous phase with an elevation in the temperature. While implementing the TEOR process, reservoir performance prediction tools require the water/oil and gas/oil relative permeability data. Many studies reported the temperature effect on two-phase water/oil relative permeability despite knowing that steam or vapor is conventionally injected, mimicking the gaseous phase during heavy oil recovery. Thus, this requires the knowledge of temperature effect on two-phase gas/liquid relative permeability as well. However, limited studies are reported in the literature regarding the temperature dependency of relative permeability in gas/liquid systems; offer no census about its effects. The scarcity of such studies in the literature is due to the lack of systematic experimental studies and complications observed while conducting the higher temperature tests to mimic the thermal EOR. Hence, the objective of this study was to examine the temperature effect on two-phase gas/liquid relative permeability at varying temperatures from 64 to 132 °C using a systematic and reliable experimental process.In this study, Poly Alpha Olefin (PAO-100) was used as the oleic phase, deionized water as the immobile phase, and nitrogen gas as the displacing phase in a clean unconsolidated sandpack under the confining pressure around 1000 psi. Furthermore, Johnson-Neumann-Bossler (JBN) method was opted to interpret the two-phase gas/liquid relative permeability curves from the displacement data, i.e., cumulative oil production and pressure drop measured across the sandpack. The experimental observation suggests that irreducible water saturation and endpoint oil relative permeability are temperature independent. The residual oil saturation decreased with the increase in temperature and led to a higher endpoint relative permeability to gas. On the other hand, the oil relative permeability at equal saturation uplifted, suggesting the enhanced mobility of oil through pores with increasing temperature. On the other side, the gas relative permeability at equal saturation was temperature-insensitive other than at residual oil saturation. Also, the two-phase flow region increased with the rise in temperature as both the relative permeability curves shifted upwards, and the broader curve was observed. Hence, this study strongly suggests that the reservoir engineers or commercial reservoir simulators should account for the temperature effects on two-phase gas/oil relative permeability to efficiently predict heavy oil reservoir performance and management during the thermal enhanced oil recovery process (TEOR).

Underground Gas Storage Construction in Gas Fields with Oil Ring and Edge and Bottom Water: A Case Study

ABSTRACT Most underground gas storages (UGSs) are constructed in gas fields, but there are few UGS examples constructed in a gas field with an oil ring and edge/bottom water (OR-EBW-gas field). In areas where suitable gas fields are not available for USG development, existing gas fields with oil ring and edge and bottom water have to be used to construct UGS to balance the seasonal natural gas consumption and supply. Compared with conventional gas reservoirs, fluid distribution is much more complicated in OR-EBW-gas fields and there exist different modes for storage space plan, which brings up more uncertainty for the UGS construction. In this work, an active UGS construction in an OR-EBW-gas field is studied using a comprehensive compositional numerical model. The operation parameters are firstly determined through detailed sensitivity studies. UGS construction schemes employing different porous medium spaces are then investigated to determine the optimal one. The results indicate that UGS constructed using gas cap area is the optimal scheme. After 20 I/W cycles, the predicted working load of the UGS is 1.726 × 108 m3, which reaches the designed value of 1.7 × 108 m3. The incremental cumulative water production and oil production are 0.21 × 104m3 and 0.42 × 104m3 respectively. The study shows that it is crucial to prevent the intrusion of edge water for UGS construction in an OR-EBW-gas field. The oil ring is not suitable for UGS construction due to its poor petrophysical property, but can be used as a natural barrier to separate gas cap and edge water. The formation pressure needs to be improved when the gas cap, oil ring and edge water are selected as USG construction zones. However, it will also lead to a significant increase in the formation pressure near the main control fault, which leads to a high risk of fault failure.

Numerical simulation of polymer flooding in water flooding reservoir

Different influencing factors in the process of polymer flooding have different degrees of influence on the development effect, so it is necessary to carry out the dynamic prediction of polymer flooding before implementing the development scheme. In this study, the reservoir model of C Block is established and the production performance is fitted. The fitted reservoir model is used to study the influence of polymer concentration, injection time, injection rate multiple and injection timing on the development effect of C Block. The results show that the cumulative oil production increases gradually with the increase of polymer concentration, and combined with the principle of economic development, there is an optimal polymer concentration in C Block, which is 0.15 wt%; With the increasing of injection time and injection rate multiple, the cumulative oil production and incremental oil production (compared with water flooding) show an increasing trend; For injection timing, the earlier polymer injection is more conducive to obtaining higher cumulative oil production and oil increment. The cumulative oil production under the optimal development scheme of C block is 23.8494×104 m3, which is 1.5042×104 m3 higher than that of water flooding.

Three-dimensional physical simulation of water huff-n-puff in a tight oil reservoir with stimulated reservoir volume

Water huff-n-puff has been considered as a cost-effective method to enhance oil recovery in tight reservoirs. However, the physical simulation method for water huff-n-puff is still lacking up to now, so that the production behaviors of actual tight reservoirs cannot be reproduced and the EOR potentials cannot be evaluated directly by scaled models in the laboratory. In this study, mathematical models for water huff-n-puff processes in tight oil reservoirs with stimulated reservoir volume (SRV) were established, then the corresponding scaling criteria were proposed and verified. Taking the tight reservoir ZMY in the Ordos Basin as a prototype, three groups of three-dimensional physical simulations of water huff-n-puff under different conditions (PSM-1, PSM-2 and PSM-3) were designed based on the scaled parameters respectively, then performed favorably and compared comprehensively. The experimental results show that oil recovery of PSM-1 can be increased by 20.16% within 8 cycles, which shows great EOR potentials for the tight reservoir ZMY. Compared with PSM-1, oil recovery of PSM-2 reduces by 8.23%, which indicates that forced imbibition is quite a helpful and promoting mechanism, and oil recovery enhancement will be greatly limited if no imbibition effect is given play between the matrix and fractures. Comparatively, oil recovery reduces by 3.39% for PSM-3, which can be inferred that if fracture density relatively increases and all fractures are well connected, the matrix imbibition effect can be further strengthened, the high pressure can propagate faster, the elastic energy can supplement into the matrix deeper, and the effect of gravitational differentiation can be better utilized as well. It is found that cumulative oil production of the three physical simulations in the first several cycles is always relatively high, which implies that sufficient oil supply in physical models can be maintained. As oil-water interface rises, less oil and more water will be produced and different dynamic characteristics of cumulative oil and water production are shown. It is also found that all three groups of water cut curves have the same upward trend and the Sigmoidal-Logistic model can be employed to accurately depict the dynamic characteristics of water cut at different cycles. This study aims to establish a physical simulation method for water huff-n-puff in tight oil reservoirs with SRV based on the three-dimensional scaled model, which will be greatly helpful to understand the EOR mechanisms and production characteristics of water huff-n-puff. • Scaling criteria of water huff-n-puff in tight oil reservoirs with SRV were proposed and verified. • Three-dimensional physical simulation method for water huff-n-puff was established. • Oil recovery of physical simulation model can be increased by 20.16% within 8 cycles for a case study. • Forced imbibition and large-scale fracture network can greatly enhance oil recovery during water huff-n-puff. • The Sigmoidal-Logistic model can depict the dynamic characteristics of water cut at different cycles.

Особенности проведения гидроразрыва пласта в отложениях с трудноизвлекаемыми запасами

Introduction. When developing productive deposits containing hard-to-recover oil reserves, the main difficulty is associated with low values of the reservoir properties of the reservoirs and their significant heterogeneity. The use of hydraulic fracturing technology allows solving these problems by increasing the well drainage area, and also as a means of intensifying production. Materials and methods of research. The study of the process of hydraulic fracture development in the deposits of the Bazhenov formation in a vertical well showed that when water is injected, long narrow fractures are formed in the formation, their filling with subsequent supply of a fracturing fluid with proppant leads to an increase in the width and height of the created fracture. Due to the hydrophobic properties and increased brittleness of the rocks of the Bazhenov formation, an effect similar to hydraulic fracturing is also possible during the injection of water into the formation at high pressures, for example, when organizing a waterflooding system. Another direction is multi-zone hydraulic fracturing. The advantage of this method is the greater distribution of fractures over the area compared to point hydraulic fracturing operations. Results and Discussion. On the deposits of the Bazhenov formation, pilot work was carried out to create artificial fracturing by pumping water. The positive effect was expressed in a twofold increase in oil recovery in the pilot area. As a negative side effect, a sharp increase in water cut was noted. The experience of using multi-zone hydraulic fracturing in the conditions of the Bazhenov formation was considered on the example of the deposits of the Surgut arch. The dynamics of flow rates and cumulative oil production by wells during operation is presented. Also, a comparison was made of the main performance indicators of wells with multi-stage hydraulic fracturing with the average indicators of directional wells of the same fields. Conclusion. The pilot work conducted on water injection into the Bazhenov formation deposits unambiguously showed that additional fracturing is formed in the reservoir and the volume of additional fractured capacity is directly proportional to the volume of injected water. The experience of using multi-zone hydraulic fracturing revealed the advantages of this technology compared to directional wells. Under conditions of reservoir reservoir properties uncertainty, the creation of artificial conductivity using hydraulic fracturing may be the only way to ensure well productivity. MSHF in horizontal wells forms a system of fractures in a large volume and seems to be more effective in such conditions compared to conventional hydraulic fracturing.

Two Phase Flow Simulation of Fractal Oil Reservoir Based on Meshless Method

The reservoir is the networked rock skeleton of an oil and gas trap, as well as the generic term for the fluid contained within pore fractures and karst caves. Heterogeneity and a complex internal pore structure characterize the reservoir rock. By introducing the fractal permeability formula, this paper establishes a fractal mathematical model of oil-water two-phase flow in an oil reservoir with heterogeneity characteristics and numerically solves the mathematical model using the weighted least squares meshless method. Additionally, the method’s correctness is verified by comparison to the exact solution. The numerical results demonstrate that the fractal oil-water two-phase flow mathematical model developed using the meshless method is capable of more accurately and efficiently describing the flow characteristics of the oil-water two-phase migration process. In comparison to the conventional numerical model, this method achieves a greater degree of convergence and stability. This paper examines the effect of varying the initial viscosity of the oil, the initial formation pressure, and the production and injection ratios on daily oil production per well, water cut in the block, and accumulated oil in the block. For 10 and 60 cp initial crude oil viscosities, the water cut can be 0.62 and 0.80, with 3100 and 1900 m3 cumulative oil production. Initial pressures have little effect on production. In this case, the daily oil production of well PRO1 is 1.7 m3 at 7 and 10 MPa initial pressure. Block cumulative oil production is 3465.4 and 2149.9 m3 when the production injection ratio is 1.4 and 0.8. The two-phase meshless method described in this paper is essential for a rational and effective study of production dynamics patterns in complex reservoirs and the development of reservoir simulations of oil-water flow in heterogeneous reservoirs.

Comparisons of predictive ability of THAI in situ combustion process models with pre-defined fuel against that having fuel deposited based on Arrhenius kinetics parameters

Toe-to-heel air injection (THAI) is an in situ thermal-enhanced oil upgrading and recovery technology that makes use of a horizontal producer well for mobilised partially upgraded oil production to the surface. To design operation of the THAI process requires up-scaling lab-scale numerical model to field-scale reservoir numerical model. There are a number of up-scaling methods that were developed. However, these previous up-scaling methods only concentrated on the qualitative nature of the physicochemical processes. Furthermore, these methods have deficiencies ranging from assumption of 100% oxygen utilisation, failing to compare oil production rates for up-scaled reservoir models with and without fuel pre-defined, not reporting on the dynamics inside the reservoirs with and without fuel pre-defined, etc. As a result, this work provided in depth comparative studies of both the qualitative and quantitative physicochemical processes in numerical models containing Arrhenius-based coke deposition thermal cracking reaction (i.e. model A) and that having pre-defined fuel concentration (i.e. model F) as an initial parameter respectively. It is found that oil production started earlier in model A compared to in model F even though they have approximately similar trajectories. It is shown that by the end of the combustion period, oil recovery of 28.5% OOIP is achieved in model F which is greater than that in model A by an additional of 4.8% OOIP. It is found that the peak temperature, which indicates how healthy the combustion is at a single point only at different times, is generally considerably higher in model A than that in model F. It is further discovered that in some cases the combustion at all points might be stable and rigorous but in other cases the combustion might not be stable and rigorous at all points thereby implying that the peak temperature alone does not give the measure of the efficiency and spread of the combustion front. It is shown for the first time that pre-defining fuel concentration throughout the reservoir as is done in model F resulted in faster downward advancement and expansion of the combustion front compared to in the reservoir where the fuel is deposited based on the Arrhenius kinetics parameters (i.e. like in model A). It is also discovered that higher areal sweep of the reservoir is achieved in model F when compared to that achieved in model A. Overall, it then follows that higher volume of the reservoir of model F is combustion-swept, heat-affected, and oil-depleted compared to that in model A. These findings explain the reason why more oil is produced during the combustion period in model F than in model A. Conclusively, this first-of-a-kind study shows that pre-defining the fuel has no effect on the qualitative nature of the physicochemical processes, but has considerable influence on the quantitative parameters such as the rate of and cumulative oil production, peak temperature, areal and volumetric sweeps by the combustion zone, size of the oil-depleted zone, and size of the heat-affect zone. • Full analysis of predictive ability of THAI model F with pre-defined fuel is reported. • Model F predicted unrealistic high oil production rate & thus cumulative oil recovery. • Model F has faster downward-advancement & general expansion of the combustion fronts. • Higher reservoir volume is combustion-swept, heat-affected, & oil-depleted in model F. • Qualitative behaviours in model F are similar to those in the Arrhenius-based model A.

Application of New Water Flooding Characteristic Curve in the High Water-Cut Stage of an Oilfield

The oil production predicted by means of the conventional water-drive characteristic curve is typically affected by large deviations with respect to the actual value when the so-called high water-cut stage is entered. In order to solve this problem, a new characteristic relationship between the relative permeability ratio and the average water saturation is proposed. By comparing the outcomes of different matching methods, it is verified that it can well reflect the variation characteristics of the relative permeability ratio curve. Combining the new formula with a reservoir engineering method, two new formulas are derived for the water flooding characteristic curve in the high water-cut stage. Their practicability is verified by using the production data of Mawangmiao and Xijiakou blocks. The results show that the error between the predicted cumulative oil production and production data of the two new water drive characteristic curves is less than the error between the B-type water drive characteristic curve and the other two water drive characteristic curves. It is concluded that the two new characteristic curves can be used to estimate more accurately the recoverable reserves, the final recovery and to estimate the effects of water flooding

A real-world impact of offset frac-hits by rate transient analysis in the Bakken and Three Forks, North Dakota, USA

Production via multi-fractured horizontal wells with specific spacing units is a common development plan in shale plays. Commonly, operators drill and complete a single well in order to hold a 1280-acre spacing unit and once the acreage is secured across the asset, infill wells at each spacing unit are drilled so, depletion from the original (parent) well can be observed within the spacing unit. This will increase the likelihood of existing wells to experience inter-communication when infill wells are hydraulically fractured which has detrimental effects. Hence, understanding the effects of well timing and spacing on the performance of the overall spacing unit is critical to choose an appropriate development plan. In this regard, rate transient analysis (RTA) is an effective way to quantify the impact of offset frac-hits, hinting the changes in reservoir properties such as stimulated reservoir volume (SRV) and well productivity. In this real-world study, we used pseudo normalized pressure versus material balance square root of time plots to determine the impact of offset frac-hits on existing wells in Williston Basin, ND. The slope of the superposition time plot is inversely proportional to the product of the contacted surface area (Ac) and the square root of reservoir permeability (k), Ack, which was a good metric to evaluate early time productivity and completion effectiveness. Additionally, production look-back performed on 71 operating wells using decline curve analysis (DCA) confirmed changes in reservoir properties and production performance to determine appropriate well spacing and infill timing. Next, economic analysis for 71 wells and 13 spacing units, using a reasonable/favorable commodity pricing, to assess the investment efficiencies of each project was carried out. Results showed that offset frac-hits cause up to 50% estimated ultimate recovery (EUR) loss, up to 80% water-cut increment, and more than 40%, Ack reduction for parent wells. Wells with multi-sleeve single ball (MSSB) completion system would have 32% lower cumulative oil production per lateral foot and 50% lower EUR than open hole sliding sleeve and cemented liner plug and perf (P-n-P). Finally, more proppant and fracturing fluid volume loading not only will not increase the production, but also deteriorates well performance. Collectively, this study indicated that 5–6 wells per 1280-acre spacing is the optimal well spacing unit within the study area to set a guideline for successful future operations. Ultimately, the very detailed field practical aspects presented here which is limited in the literature and combined with theories of RTA, can become a benchmark for further verification of mathematical models.

A new computational approach to predict hot-water flooding (HWF) performance in unconsolidated heavy oil reservoirs

In this study, a new computational approach for predicting the performance of hot-water flooding in unconsolidated heavy oil reservoirs is presented. The proposed model predicts the changes in the oil–water viscosity ratio (μo/μw) by estimating the reservoir temperature distribution through porous media. Then, the dimensionless and normalized variables were redefined to forecast water fractional flow as a function of temperature and water saturation. Moreover, the proposed approach predicts the cumulative heavy oil production and recovery factor more accurately and with less required input data and runtime compared to commercial simulators such as CMG-STARS (computer modeling group), etc.Estimated results were validated using laboratory experimental data and numerical simulation outputs. A total of 4 core-flooding experiments were conducted at injection temperatures of 20–80 °C. Numerical simulation models based on the laboratory HWF tests were developed in CMG-STARS. The water–oil relative permeability curves were tuned to history match simulation results with those obtained from experiments.Finally, the predicted cumulative heavy oil productions, recovery factors (RF) and production rates by the proposed approach were compared to the results from the laboratory sandpacked tests and simulation runs for three scenarios. The relative errors between heavy oil recovery factors obtained from computational approach and experimental data were measured to be 11.01%, 14.51% and 13.69% for injection temperatures of 40, 60 and 80 °C, respectively.

A Novel Mathematical Model for Fracturing Effect Evaluation Based on Early Flowback Data in Shale Oil Reservoirs

For shale oil reservoirs, the horizontal well multistage fracturing technique is mostly used to reform the reservoir in order to achieve economic and effective development. The size of the reservoir reconstruction volume and the quantitative characterization of the fracture system are of great significance to accurately predict the productivity of shale oil wells. There are few flowback models for shale oil reservoirs. To solve this problem, first, a physical model of the simultaneous production of oil, gas, and water in the early flowback stage of shale oil development is established using the material balance equation for a fracture system. Second, the physical model of the underground fracture system is simplified, which is approximately regarded as a thin cylindrical body with a circular section. The flow of the fluid in the fracture system is approximately regarded as radial flow. In this model, the expansion of the fluid and the closure of the fracture are defined as integrated storage coefficients to characterize the storage capacity of the fracture system. Then, the curves illustrating the relationships between the oil-water ratio and the cumulative oil production and between the gas-water ratio and the cumulative gas production are drawn, and the curves are used to divide the flowback stage into an early stage and a late stage because the flowback process of shale oil wells exhibits obvious stage characteristics. Finally, the reservoir reconstruction volume and the related hydraulic fracture parameters are estimated based on the material balance method, and the rationality of the model is verified via numerical simulation. The interpretation results of this novel model are more accurate, making it an effective way to evaluate the hydraulic fracture parameters and transformation effect, and it has guiding significance for the evaluation of the hydraulic fracturing effect in the field.

Comprehensive Effects of Polymer Flooding on Oil–Water Relative Permeabilities

Abstract Many reports have indicated that, in contrast to waterflooding, oil–water relative permeabilities in polymer flooding are influenced by the polymer properties, such as adsorption and viscoelasticity. Long-term injected polymer solutions flush the reservoir porous media causing wettability alteration and residual oil reduction, which is also an important factor for oil–water relative permeabilities. Therefore, the comprehensive effects of polymer properties and dynamic flushing on two-phase percolation behavior have been the focus of research. In this study, polymer flow experiments, including pre-shearing, relative permeability, and long-term erosion tests, were first conducted. Then, a flushing-interpolation model, including polymer concentration interpolation and surface flux characterization, was developed to dynamically describe the two-phase flow characteristics. Based on the experimental results and the presented dynamic model, polymer-flooding simulations were conducted to analyze the performance of the well and the distribution of the remaining oil. The results indicate that flushing reduces the residual oil saturation, and the viscoelasticity effect further broadens the predominant flushing channels horizontally; both effects lead to higher cumulative oil production and a lower water-cut. Additionally, including the flushing effect in the polymer-flooding model leads to a more reliable numerical prediction of the remaining oil distribution. To account for the comprehensive effects of viscoelasticity and erosion in field applications, water-cut history matching was performed for the studied well group, and the error decreased to 4.39%. Finally, the optimal polymer concentration for high-concentration polymer-flooding programs was determined to be 1450 mg/L.

Decision-Making Techniques for Water Shutoff Using Random Forests and Its Application in High Water Cut Reservoirs.

The major oil fields are currently in the middle and late stages of waterflooding. The water channels between the wells are serious, and the injected water does little effect. The importance of profile control and water blocking has been identified. In this paper, the decision-making technique for water shutoff is investigated by the fuzzy evaluation method, FEM, which is improved using a random forest, RF, classification model. A machine learning random forest algorithm was developed to identify candidate wells and to predict the well performance for water shutoff operation. A data set consisting of 21 production wells with three-year production history is used, where out of the mentioned well data, 70% of them are implemented for training and the remaining are used for testing the model. After fitting the model, the new weights for the factors are established and decision-making is made. Accordingly, 16 wells out of 21 wells are selected by the FEM where 8 wells out of 21 wells are selected by the new factor weight created by RF for water shutoff. A numerical simulation model is established to plug the selected wells by both methods after which the influence of plugging on water cut, daily oil production, and cumulative oil production is compared. The paper shows that the reservoir had a better performance after eight wells were selected using a new weighting system created by RF instead of the 16 wells that were selected using the FEM model. The paper also states that the new weighting model’s accuracy improved the decision-making abilities of the wells.

Sichuan super gas basin in southwest China

A sedimentary basin is classified as a super basin when its cumulative production exceeds 5 billion barrels of oil equivalent (6.82×108 t of oil or 7931.66×108 m3 of gas) and its remaining recoverable resources are at least 5 billion barrels of oil equivalent. By the end of 2019, the total output of oil and gas in Sichuan Basin had been 6569×108 m3 with the gas-oil ratio of 80:1, and the total remaining recoverable resources reached 136 404×108 m3, which makes it as a second-tier super basin. Because the output is mainly gas, it is a super gas basin. The reason why the Sichuan Basin is a super gas basin is that it has four advantages: (1) The advantage of gas source rocks: it has the most gas source rocks (9 sets) among all the basins in China. (2) The advantage of resource quantity: it has the most total remaining recoverable resources among all the basins in China (136404×108 m3). (3) The advantage of large gas fields: it has the most large gas fields (27) among all the basins in China. (4) The advantage of total production: by the end of 2019, the total gas production had been 6 487.8×108 m3, which ranked the first among all the basins in China. There are four major breakthroughs in natural gas exploration in Sichuan Basin: (1) A breakthrough in shale gas: shale gas was firstly found in the Ordovician Wufeng-Silurian Longmaxi formations in China. (2) A breakthrough in tight sandstone gas: the Triassic Xu2 Member gas reservoir in Zhongba gas field is the first high recovery tight sandstone gas reservoir in China. (3) A breakthrough in giant carbonate gas fields. (4) A breakthrough in ultra-deep gas reservoir. These breakthroughs have led to important progress in different basins across the country. Super basins are classified according to three criteria: cumulative production and remaining recoverable resources of oil and gas, tectonic attributes of the basin, and the proportions of oil and gas in cumulative oil and gas production.

A Two-Phase Flow Model for Reserves Estimation in Tight-Oil and Gas-Condensate Reservoirs Using Scaling Principles

Summary A common approach to forecast production from unconventional reservoirs is to extrapolate single-phase flow solutions. This approach ignores the effects of multiphase flow, which exist once the reservoir pressure falls below the bubble/dewpoint. This work introduces a new two-phase (oil and gas) flow solution suitable to extrapolating oil and gas production using scaling principles. In addition, this study compares the application of the two-phase and the single-phase solutions to estimates of production from tight-oil wells in the Wolfcamp Formation of west Texas. First, we combine the oil and the gas flow equations into a single two-phase flow equation. Second, we introduce a two-phase pseudopressure to help linearize the pressure diffusivity equation. Third, we cast the two-phase diffusion equation into a dimensionless form using inspectional analysis. The output of the model is a predicted dimensionless flow rate that can be easily scaled using two parameters: a hydrocarbon pore volume and a characteristic time. This study validates the solution against results of a commercial simulator. We also compare the results of both the two-phase and the single-phase solutions to forecast wells. The results of this research are the following: First, we show that single-phase flow solutions will consistently underestimate the oil ultimate recovery factors (URFs) for solution gas drives. The degree of underestimation will depend on the reservoir and flowing conditions as well as the fluid properties. Second, this work presents a sensitivity analysis of the pressure/volume/temperature (PVT) properties, which shows that lighter oils (more volatile) will yield larger recovery factors for the same drawdown conditions. Third, we compare the estimated ultimate recovery (EUR) predictions for two-phase and single-phase solutions under boundary-dominated flow (BDF) conditions. The results show that single-phase flow solutions will underestimate the ultimate cumulative oil production of wells because they do not account for liberation of dissolved gas and its subsequent expansion (pressure support) as the reservoir pressure falls below the bubblepoint. Finally, the application of the two-phase model provides a better fit when compared with the single-phase solution. The present model requires very little computation time to forecast production because it only uses two fitting parameters. It provides more realistic estimates of URFs and EURs, when compared with single-phase flow solutions, because it considers the expansion of the oil and gas phases for saturated flow. Finally, the solution is flexible and can be applied to forecast both tight-oil and gas condensate wells.

Study on Production Optimization Method of Fractured Reservoir Based on Connectivity Model

Due to the extensive development of fractures and serious heterogeneity in fractured reservoirs, it is difficult for the traditional numerical simulation method to invert its geology, which greatly limits the efficiency and accuracy of simulation and cannot realize the real-time optimization of production scheme. The connectivity model can only consider the two characteristic parameters of conductivity and connectivity volume, which does not involve complex and rigorous geological modeling. It can quickly and accurately reflect the state of the real reservoir, greatly reducing the simulation time, and is suitable for real-time production performance prediction of the reservoir. Due to the large difference in conductivity of fractured reservoirs, the difficulty of fitting increases. In this paper, the connectivity model is first applied to fractured reservoirs to realize the production dynamic simulation of fractured reservoirs. The optimization principle is used to optimize the injection-production scheme with the economic net present value as the objective function. In order to verify the method, the connectivity model is applied to Mu 30 of Changqing Oilfield in this paper. The results show that this method can effectively reflect the real production situation of the oilfield and the connectivity of the reservoir, and the simulation time is relatively fast. After optimization, the cumulative oil production of the reservoir increases by 8.1%, the cumulative water injection decreases by 2.3%, and the rising rate of water cut decreases by 58.8%, indicating that the connectivity model can realize the real-time production optimization of the reservoir.

CAPACITANCE RESISTANCE MODEL (CRM) APPLICATION TO RAPID EVALUATE AND OPTIMIZE PRODUCTION IN PERIPHERAL WATERFLOOD FIELD, PANDHAWA FIELD CASE STUDY

Waterflooding is one of the most effective methods to improve oil recovery in mature fields because of its high success ratio, easy in application and cost efficiency. Development until now has shown that Capacitance Resistance Model (CRM) can be used as alternative from reservoir model and simulation studies. CRM can be used as model to predict reservoir characterization and reservoir performance quickly and accurately with only require historical production and injection data. CRM characterizes the reservoir by calculating the connectivity value and the response delay between the injections well and the production well as unknown parameters. Pandhawa Field is a heterogeneous carbonate reservoir with an average permeability of 65 mD with peripheral waterflood since 20 years ago. By knowing the injection efficiency, the optimization process can be carried out by increasing the water injection rate in injection wells that have high efficiency and vice versa. In this study, the performance of waterflood is analyzed using the Capacitance-Resistance Injection-Production Model (CRM-IP) to determine the connectivity of each injection and production well. This study also discuss CRM-IP implementation on MATLAB programming language and optimization of injection rate allocation for the most optimum cumulative oil production. Result of this study indicate total additional oil 505 MBO will be obtained during 120 months period by conduct redistribution water injection management for each injector. By using CRMIP methodology, waterflood management in this field can be done much faster, therefore decision taken for this field will be more effective.

Effect of water injection on subsequent polymer floods in viscous oil reservoirs

Waterfloods (WF) in viscous oil reservoirs (>100 cp) are unstable and usually bypass a large amount of oil. Polymer floods (PF) often follow waterfloods and improve oil recovery through improved sweep efficiency. This study examines the effect of prior waterflood on the subsequent polymer flooding. The displacement of a viscous oil by water and polymer solution is studied in a custom-built 2D porous medium. Floods are conducted at the interstitial velocity of 1 ft/day with the oil viscosity (μo) of 390 cp at 25 °C. The extent of waterflood beyond the water breakthrough (WBT) is varied from 0 to 0.5 injected pore volume (PV). Polymer injection after the waterflood displaces the oil which further pushes the brine in the established water fingers and is reflected in a decrease in the water cut down to 0–0.3. After dewatering of the fingers, the polymer solution displaces the oil across the whole cross-section. The final recoveries range from 73 to 83 % of the original oil in place (OOIP). Injecting the viscous solution at earlier stages results in earlier production, higher crest of oil cut (fo) and slightly higher cumulative oil production (NpD). This work can help engineers optimize the strategy of polymer flooding in viscous oil reservoirs.

An injection optimization decision-making tool using streamline based fuzzy logic workflow

This paper presents an adaptive approach to optimize field injection strategies using streamline-based well allocations coupled with fuzzy logic. The strength of our approach comes from the fact that streamlines are generated by running a full-physics reservoir simulator. Streamlines provide great insights about well pattern connectivity and good allocation factors allowing the injection efficiency (IE) for each pattern to be determined. Fuzzy logic can simulate human thinking and handle different categories of information including linguistic, imprecise, approximate, and overlapping to name a few. This paper presents a genuine approach for field injection optimization using a streamlined-based fuzzy logic system. In this work, we present an adaptive streamline-based fuzzy logic system that uses three input parameters namely injection efficiency (IE), water cut (WC), and injection loss to aquifer to assign an injector ranking index (IRI) according to injector performances. The workflow then smartly redistributes water injection by accounting for operational constraints and number of connected producers in a pattern in addition to the IRI. The workflow examines the low performers (i.e., low and medium IRI categories) and assigns different injection reduction factors for each injector in these categories. Then, the total amount of reduced injection is assigned to high performers (i.e., high IRI) while ensuring no operational constraint is violated, such as bottom-hole pressure (BHP) and capacity of pumps. This approach has been tested on a dual-porosity dual-permeability (DPDP) conceptual simulation model. The area of interest has two rows of injectors: downdip and updip. The updip injectors are the focus of the study. The results of applying this approach show noticeable improvements in injection efficiency for most wells in the area of interest ensuring better sweep, good pressure support, and improving cumulative oil production. We believe combining both technologies, namely streamlines and fuzzy logic, can provide reservoir engineers with a robust decision-making tool to attain a more successful field-wide water injection strategy.

Hybrid physics and data-driven modeling for unconventional field development and its application to US onshore basin

The objective of this study is to develop a hybrid model by combining physics and data-driven approach for optimum unconventional field development. We used physics-based reservoir simulations to generate training datasets. These uncalibrated priors were incorporated into data-driven machine learning (ML) algorithms so that the algorithms can learn the underlying physics between reservoir simulation input and output, cumulative oil production for parent and child wells. The reservoir simulations in a single half-cluster model consists of injection and production phases. This allows the algorithm to relate the impact of completion design, well spacing and timing to the production profiles. After performing a sensitivity analysis to reduce the number of training inputs, more than 20,000 simulations results were generated as the training data. The best accuracy, R2 = 0.94, was achieved with the neural network model after tuning hyper-parameters. Then, we incorporated the hybrid model with the genetic algorithm to perform efficient history matching to calibrate model parameters and predict estimated ultimate recovery (EUR) and net present value with 10% discount rate (NPV10). The great efficiency in the hybrid model takes only several minutes to complete a single well history matching. The calibrated model shows that the prediction from the hybrid model is physically meaningful compared to actual reservoir simulations, capturing the impact of fracture geometry, child well spacing and timing on the well production. With multiple history matching results, we populated value acreage maps (e.g., EUR and NPV10) which can benefit the unconventional field development planning. Lastly, a blind test was conducted in an area of interest to demonstrate that the proposed workflow can effectively predict a well performance in the area without sufficient data, utilizing calibrated model parameters from history matched results of adjacent wells. The proposed model can provide quick and scalable solutions that honor underlying physics to help decision making on unconventional field development based on production profile and economic metrics with various completion designs.