Optimal Water Injection Research Articles

Optimizing Water Injection Performance by Using Sector Modeling of the Mishrif Formation in West Qurna-1 Oil Field, Southern Iraq

The regular job of a reservoir engineer is to put a development plan to increase hydrocarbon production as possible and within economic and technical considerations. The development strategy for the giant reservoir is a complex and challenging task through the decision-making analysis process. Due to the limited surface water treatment facility, the reservoir management team focuses on minimizing water cut as low as possible by check the flow of formation and injected water movement through the Mishrif reservoir. In this research, a representative sector was used to make the review of water injection configuration, which is considered an efficient tool to make study in a particular area of the entire field when compared with the full-field model on the basis of time-consuming and computational analysis. The sector model was neighboring by extra grid blocks and three pseudo wells as injector wells to realize the pressure on the sector boundary, which attained an acceptable history matching. The fluid model and physics model were introduced by using Pressure Volume Temperature data of well involved in the study area and two relative permeability curves. Fourteen wells were utilized in this work, four wells are injectors, and the rest are producer. The development scenarios were implemented by setting various targets of oil production and different water injection rates required for pressure maintenance operations. Optimization of water cut has been applied by adjustment of production and injection rates and shut off the high water cut intervals. The results obtained from this study showed that the inverted 9-spot has a good recovery which is illustrated in the case_2C, the production rate was (49,000 STB/D) with minimum water cut (27.5%) as compared with a five-spot pattern.

Effect of Dynamic Imbibition on the Development of Ultralow Permeability Reservoir

To explore the methodology for improving ultralow permeability reservoir recovery, cores of ultralow permeability reservoirs in China’s Ordos Basin were selected to study the dynamic imbibition micromechanism of crude oil in nanopore throat through core-flooding laboratory experiment and nuclear magnetic resonance (NMR) observation. In the meantime, the microimbibition characteristics and dynamic discharge of oil between matrix and fracture in partially closed boundary reservoirs were simulated to utmostly reflect the actual reservoir conditions. Our findings suggest that dynamic imbibition between fracture and matrix serves the core technology for improving the recovery of ultralow permeability reservoirs, while the main factors affecting dynamic imbibition efficiency include wettability, permeability, injection rate, fracture, water huff and puff cycles, and soaking time. Wettability, in particular, weighs the most, and imbibition can take place either on water-wet rocks or transformed oil-wet rocks with an imbibition agent added in during the waterflooding process. Meanwhile, the higher the permeability is in place, the greater the dynamic imbibition recovery might achieve. The experiments indicate that the dynamic imbibition recovery of a fractured core is 16.26% higher than that of a nonfractured core. Additionally, fractures can not only enhance imbibition recovery but also accelerate the occurrence of dynamic imbibition. The optimal water injection rate of dynamic imbibition is 0.1 mL/min; the reasonable huff and puff cycle of the ultralow permeability reservoirs tends to be two to three cycles; the optimal soaking time of ultralow permeability reservoir is speculated to be 30 days. Finally, the field practice shows that after Stimulated Reservoir Volume (SRV) and dynamic imbibition in 5 horizontal wells in An83 oilfield, there is a remarkable drop in water cut and a noticeable rise in oil production. This research underpins the significance of a dynamic imbibition effect in the development of ultralow permeability oilfield.

First time-lapse OBN in Bonga deepwater offshore field

Time-lapse seismic data from Bonga Field, located in deepwater Nigeria, have delivered excellent results previously from dedicated streamer seismic surveys (2000, 2008, and 2012) that image changes in amplitude due to water replacing oil. One challenge with the streamer data is the presence of a floating production storage and offloading (FPSO) unit. It is difficult to accurately repeat streamer acquisition geometry in economically important updip regions of reservoirs that lie beneath the FPSO. To ensure an accurate repeat of this area, we acquired an ocean-bottom node (OBN) survey in 2010 and carried out the first time-lapse OBN repeat of the survey in 2018. Time-lapse processing of the OBN data produced excellent results. We obtained an OBN-on-OBN normalized root mean square (NRMS) difference repeatability of 6%. This was an improvement over the 12% NRMS for streamer-on-streamer repeats. The OBN data quality was unaffected by the FPSO, enabling us to properly image the changes occurring in this area. The 4D OBN interpretation was used to identify bypassed oil opportunities. The data also were used to derisk well placement, optimize water injection, and update the dynamic reservoir models. The new models are essential to enhance predictability and field performance. We also analyzed an area northwest of the field where we extended the 2018 OBN acquisition and compared it to streamer data to optimize a new injection well location.

Compositional Simulation, Artificial Intelligence Optimize Water Injection

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 198995, “Low-Salinity Water-Injection Optimization in the Namorado Field Using Compositional Simulation and Artificial Intelligence,” by Diana Mercado Sierra, SPE, Argenis Alvarez Rojas, and Victor Salazar Araque, Computer Modelling Group, prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, 27-31 July, Virtual. This paper has not been peer reviewed. The complete paper discusses optimization of a development plan involving low-salinity water injection (LSWI). This methodology combines compositional simulation and a mathematical optimization tool that uses artificial intelligence to maximize the net present value (NPV) of the project under evaluation. The adapted methodology allowed an optimal development plan, considering the uncertainty associated in the reservoir, by use of multiple geostatistical realizations and simultaneous history-matched models. LSWI LSWI is an enhanced-oil-recovery technique in which the salinity of the injected water is controlled with the objective of increasing the recovery factor. Of the mechanisms proposed for LSWI, wettability alteration is the most widely accepted for describing the increase of the recovery factor. The wettability change in reservoirs with the presence of sand-stones mainly is attributed to the multionic exchange between the injected fluid and the clay surface, as is the double layer expansion. From a technical point of view, the LSWI success is related strongly to reservoir lithology. An integrated analysis and optimization study was performed using numerical simulation to evaluate LSWI as an alternative for increasing the recovery factor in the Namorado field in the Campos Basin of Brazil.

Physical simulation of waterflooding development in large-scale fractured-vuggy reservoir considering filling characteristics

The Fractured-vuggy reservoir is one of the world's most important reservoir types and has great exploration and development potential. However, due to the unique geological characteristics of the fractured-vuggy reservoir and limited understanding of its waterflooding development law, it is more difficult to develop. To strengthen the study of the oil-water flow mechanism and the waterflooding development law of fractured-vuggy reservoirs, we built a large-scale 3-D physical model that can reflect the geological morphology and structure of typical well groups. On the basis of the similarity theory, we determined the parameters of the model and its physical simulation. The physical model was applied to the experimental study of the waterflooding development process and the analysis of relevant influencing factors. The results show that the low-high mode can effectively touch the reserves in high parts, and the development effect is better than that of the high-low mode. There is an optimal water injection rate in waterflooding development to maximize the recovery. Weak bottom water energy at the bottom of the reservoir plays a positive role in waterflooding development, whereas strong bottom water energy increases the risk of premature water breakthrough, which is not conducive to waterflooding development. The substantial difference in oil and water viscosities makes viscous fingering more obvious, which reduces the stability of the displacement process and reduces the efficiency of waterflooding development. This study may provide strong guidance to further understand the oil-water flow law and improve waterflooding development efficiency for fractured-vuggy reservoirs.

Concurrent-Separate Constant Pressure Water Injection Design Optimization Technique Considering the Threshold Pressure Gradient

A new complex technique for optimizing the design of concurrent-separate constant pressure water injection (CSI), considering the threshold pressure gradient, is proposed. First, the regularity of the each production unit water omnidirectional movement was determined based of the constructed 3D-geological model of the studied field object, and then the critical values of the inefficient water injection into multilayer formations process indicators were calculated based on the obtained data. Second, using an intelligent borehole monitoring and control system, the threshold pressure of water injection into the productive reservoir was determined and CSI special blanks were constructed under constant pressure, taking into account the threshold pressure gradient in injection wells. Third, a procedure has been developed for determining the optimal water injection pressure of each production facility into the productive reservoir during the development of multilayer oil fields. The application of the proposed technique for optimizing the CSI design under constant pressure is by an example of field data from the Daqing oil field of the People’s Republic of China (PRC). The calculation results show that the injected under the constant pressure water efficiency factor value increased significantly by 8.6% due to the sensible separation of the volume of water injected into the productive reservoir. The proposed technique may be useful for CSI designing optimization on other oil fields.

Geothermal Power Production from Abandoned Oil Reservoirs Using In Situ Combustion Technology

Development of geothermal resources on abandoned oil reservoirs is considered environmentally friendly. This method could reduce the rate of energy consumption from oil fields. In this study, the feasibility of geothermal energy recovery based on a deep borehole heat exchanger modified from abandoned oil reservoirs using in situ combustion technology is investigated. This system could produce a large amount of heat compensated by in situ combustion in oil reservoir without directly contacting the formation fluid and affecting the oil production. A coupling strategy between the heat exchange system and the oil reservoir was developed to help avoid the high computational cost while ensuring computational accuracy. Several computational scenarios were performed, and results were obtained and analyzed. The computational results showed that an optimal water injection velocity of 0.06 m/s provides a highest outlet temperature of (165.8 °C) and the greatest power output of (164.6 kW) for a single well in all the performed scenarios. Based on the findings of this study, a geothermal energy production system associated with in situ combustion is proposed, specifically for economic reasons, because it can rapidly shorten the payback period of the upfront costs. Modeling was also performed, and based on the modeling data, the proposed technology has a very short payback period of about 4.5 years and a final cumulative net cash flow of about $4.94 million. In conclusion, the present study demonstrates that utilizing geothermal resources or thermal energy in oilfields by adopting in situ combustion technology for enhanced oil recovery is of great significance and has great economic benefits.

SYSTEMATIZATION OF METHODS OF WATER INJECTION IN WELLS

Setting the required injection water rates for injection wells is a key factor for oil field successful operation using waterflooding. The success of such activities could reduce the water cyclical nature at field level, crosssection and structure; improve the ratio of water and oil and the wells cleaning efficiency; improve production and recovery of oil by channeling water to specific zones and areas and reduce material costs by improving water use. As a rule, on-site engineers adjust the fluid injection rate using heuristics. While this improves performance, we believe that a more systematic approach can be developed. In accordance with the limitations, including the available water total amount, the maximum and minimum injection rate, the maximum total production liquid for the manufacturer and the sensor installation, to determine the optimal water injection rate, based on the established distribution factor, the linear optimizer was applied programming. This approach has been experimentally tested at the Rosneft Samaraneftegaz field. The decline curve of oil production is calculated within 6 months. The results of a three-month experimental test showed that optimized oil production fits well with the historical six-month decline curve, about 22 % less than the total daily water supply, we also observed a 2 % increase over the historical two-month decline curve (also by 22 % less total daily water injection). These results show that a systematic method can ensure the optimization of target water injection rates.

Numerical simulation of simultaneous exploitation of geothermal energy and natural gas hydrates by water injection into a geothermal heat exchange well

A new geothermal energy-assisted natural gas hydrate recovery method (GEAN) that can simultaneously exploit geothermal energy and natural gas hydrates (NGHs) by injecting water into a geothermal heat exchange well was proposed in this paper. GEAN involves no hydraulic fracturing in the geothermal reservoir and, thus, avoids the fracturing cost and decreases the damage to the geothermal reservoir. Moreover, compared with conventional thermal stimulation methods, no surface fluid heating is required. Thus, GEAN produces less carbon emissions and is more environmentally friendly. A numerical simulation model was then built to investigate the heat mining rate, the along-well water temperature, and the development performance of the hydrate-bearing layer (HBL). Finally, factors that affect the heat exchange performance were analyzed. With a geothermal reservoir temperature of 135 °C and an 1800-m-long horizontal wellbore through the geothermal reservoir, it was found that the injected water, which originally had an ambient temperature of 20 °C, returns to the HBL with a temperature of up to 89.4 °C after being heated by the geothermal heat exchange well. Moreover, the heat mining rate is over 0.3 MW throughout the production process. Therefore, the feasibility of using geothermal energy to recover NGHs by the GEAN method was proven. Compared with the depressurization method, GEAN achieved an increment cumulative gas production of 63.9%. The HBL candidate with a higher geothermal gradient is preferred due to the corresponding higher temperature of the geothermal reservoir and better heat exchange performance. The optimal water injection rate and horizontal wellbore length in the geothermal reservoir are 150 m3/d and 1800 m, respectively. Performances of the heat exchange well and HBLs could be more effectively improved by properly raising the insulation level.

Mineralogical alterations in calcite powder flooded with MgCl2 to study Enhanced Oil Recovery (EOR) mechanisms at pore scale

Seawater injection into chalk-reservoirs on the Norwegian Continental Shelf has increased the oil recovery and reduced seabed subsidence, but not eliminated it. Therefore, understanding rock–fluid interactions is paramount to optimize water injection, predict and control water-induced compaction. Laboratory experiments on onshore and reservoir chalks have shown the need to simplify the aqueous chemistry of the brine, and also the importance of studying the effect of primary mineralogy of chalk to understand which ions interact with the minerals present. In this study, the mineralogy of the samples tested, are simplified. These experiments are carried out on pure calcite powder (99.95%), compressed to cylinders, flooded with MgCl2, at 130 °C and 0.5 MPa effective stress, for 27 and 289 days. The tested material was analysed by scanning and transmission electron microscopy, along with whole-rock geochemistry. The results show dissolution of calcite followed by precipitation of magnesite. The occurrence and shape of new-grown crystals depend on flooding time and distance from the flooding inlet of the cylinder. Crystals vary in shape and size, from a few nanometres up to 2 μm after 27 days, and to over 10 μm after 289 days of flooding and may crystallize as a single grain or in clusters. The population and distribution of new-grown minerals are found to be controlled by nucleation- and growth-rates along with advection of the injected fluid through the cores. Our findings are compared with in-house experiments on chalks, and allow for insight of where, when, and how crystals preferentially grow.

Improved CRM Model for Inter-Well Connectivity Estimation and Production Optimization: Case Study for Karst Reservoirs

Due to the coexistence of multiple types of reservoir bodies and widely distributed aquifer support in karst carbonate reservoirs, it remains a great challenge to understand the reservoir flow dynamics based on traditional capacitance–resistance (CRM) models and Darcy’s percolation theory. To solve this issue, an improved injector–producer-pair-based CRM model coupling the effect of active aquifer support was first developed and combined with the newly-developed Stochastic Simplex Approximate Gradient (StoSAG) optimization algorithm for accurate inter-well connectivity estimation in a waterflood operation. The improved CRM–StoSAG workflow was further applied for real-time production optimization to find the optimal water injection rate at each control step by maximizing the net present value of production. The case study conducted for a typical karst reservoir indicated that the proposed workflow can provide good insight into complex multi-phase flow behaviors in karst carbonate reservoirs. Low connectivity coefficient and time delay constant most likely refer to active aquifer support through a high-permeable flow channel. Moreover, the injector–producer pair may be interconnected by complex fissure zones when both the connectivity coefficient and time delay constant are relatively large.

The influence of air side and fuel side water addition on engine’s behaviour of a biofuel based compresion ingnition engine under oxygen enriched combustion

The effect of water injection at the air side and water addition at fuel side on engine?s performance of a Diesel engine was studied under oxygen enriched intake air using neat mahua oil as fuel. Initially experiments were carried out using neat mahua oil as fuel with different oxygen concentrations such as 21% (ambient), 22.4%, 23.8%, and 24.7% by volume at the air side. The optimal oxygen concentration was found based on the engine?s brake thermal efficiency. At the optimal oxygen concentration water injection was done on air side at 4% by mass and the experiments were repeated with neat mahua oil as fuel under oxygen enrichment mode. Finally, mahua oil emulsion was prepared using the same amount of water (i. e. 4%) and tested in the engine. A comparative study was made for the same amount of water (i. e. 4% as optimal) for water injection and neat mahua oil emulsion on engines behavior. Oxygen enrichment increased the brake thermal efficiency with all concentrations and reached the maximum value from 25.2% with ambient oxygen to a maximum of 30.6% at 23.8% of oxygen enrichment at the maximum brake mean effective pressure of 5.4 bar whereas it was 30.8% with neat diesel. The smoke, HC, and CO emissions were significantly reduced with oxygen enrichment. However, oxygen enrichment increased the NO emissions at all concentrations. Injection of water and emulsification techniques reduced the NO emissions considerably. Emulsification showed more reduction in NO emission than water injection for the same amount of water. It was concluded from the study that neat mahua oil could be effective used as fuel in compression ignition engines by combusting it under oxygen enriched condition. The optimal oxygen concentration of 23.8% could be recommended for the highest brake thermal efficiency. Injection of water at the intake manifold and emulsification techniques could solve the problem of higher NO emissions. The optimal amount of water that could be injected without affecting the engines power and brake thermal efficiency could be recommended as 4% by volume. Emulsification has the added advantage of further improvement in engine?s brake thermal efficiency.

Influence of Eccentric Water Injection on Shaft Wall Stability

The approach of water injection is an effective way to prevent shaft failure. However, due to the building existence or the need for adding a single water injection hole, the symmetric arrangement of the water injection borehole becomes more and more difficult. Therefore, eccentric water injection becomes a water injection method that has to be used. In this paper, the numerical simulation method was used to study the influence of eccentric water injection on the shaft stability by setting the water pressure and injection position distance from the shaft. The results showed that the larger the water injection pressure was, the smaller the vertical compressive stress on the shaft wall was and the larger the strata uplift was. The farther the injection position from the shaft was, the larger the vertical compressive stress on the shaft wall was. It also showed that the farther injection position distance from the shaft was, the weaker the lateral transfer of water pressure was, and the larger the vertical pressure difference between the water injection side and the opposite side was. Combined with the simulation results and the pre-industrial tests, the optimal water injection engineering parameters were determined as injection pressure of 0.3 MPa with injection position 50 m away from the shaft.

Stable Production Technology for Horizontal Well Development in Shallow Water Delta Oilfield of Bohai Bay, China

BZ Oilfield is a medium-sized oilfield with shallow delta facies deposits in Bohai Bay of China, compared with fluvial and delta facies oilfields, there is no mature experience for reference of reservoir configuration, well pattern arrangement and development model in offshore oilfields in China. In view of the difficulty in describing the reservoir configuration of shallow water delta, the single distributary sand dam in shallow water delta is characterized by well-seismic combination and multi-attribute constraints. The mathematical mechanism model of pinch-out position of sand body is established, fine characterization of BZ shallow water delta reservoir is put forward. The horizontal well pattern arrangement type for shallow water delta reservoir is proposed and the method of well pattern optimization based on vertical displacement theory is put forward. A method of inversion of reservoir connectivity using production dynamic data by numerical well testing is proposed and a new method for optimizing water injection rate in water injection wells is proposed aiming at the difficulty of recognizing injection-production connectivity of shallow water delta reservoirs. The fine configuration of BZ shallow water delta reservoir based on distributary sand dam is proposed, which guides the recognition of remaining oil distribution law. By deploying adjustment wells, the water flooding coincidence degree of actual drilling is 86% compared with that of pre-drilling prediction, which indicates that the research results of reservoir configuration can effectively guide the understanding of oilfield geology. Through the theoretical well arrangement type of vertical displacement of single sand body in horizontal wells of shallow water delta reservoir, a high water flooding recovery rate of 35% is achieved in primary well pattern. The connectivity coefficients of injection-production boundary of shallow water delta reservoir configuration are calculated, and the water injection distribution coefficients are obtained by normalizing the directional coefficients. This paper presents a configuration method based on multi-attribute fusion under the constraints of sedimentary process. In this paper, a shallow water delta reservoir configuration method based on multi-attribute fusion constrained by sedimentary process is proposed, and the injection-production connectivity coefficient and injection well distribution coefficient of the configuration boundary are calculated.

Numerical modeling study of a man-made low-permeability barrier for the compressed air energy storage in high-permeability aquifers

Compressed air energy storage (CAES) is a grid-scale energy storage technology for intermittent energy, as proven by the decades-long successful operation of two existing compressed air energy storage in cavern (CAESC) power plants. Because of the limited availability of salt domes appropriate for CAESC, the more widely available aquifers (compressed air energy storage in aquifers, CAESA) have recently attracted considerable attention as candidates for CAES. An ideal aquifer for CAESA is highly permeable around the well to facilitate easy injection and withdrawal of air, but the high-permeability region is surrounded by low-permeability zones to minimize the loss of injected air and decrease in energy efficiency. However, such ideal geological structures are not always available in nature. Therefore, the potential of creating man-made low-permeability barrier in high-permeability aquifers is very interesting. In this paper, we investigate the feasibility of man-made low-permeability barriers in high-permeability aquifers using the numerical simulator TOUGH2/Gel to calculate the three-component flow (including a miscible gelling liquid). The simulation results show that an expected low-permeability barrier can be created by injecting grout with certain properties, and the altered aquifer performs well for CAESA. Additional sensitivity studies are also performed to reveal the effects of the various factors on the success of the low-permeability barrier creation, including the critical solidification concentration, the scale factor of the time dependence of the grout viscosity, the relative density of the grout, and the volume of the follow-up water injection. The results indicate that, in a horizontal aquifer, low critical solidification concentrations, and small scale factors are generally preferred and the density of grout should be close to that of the in situ water. For the given volume of the injected grout, there is an optimal follow-up water injection that will create the largest storage space without damaging the barrier. These results may help to extend the candidate sites for CAESA and the prospect of large scale energy storage.

Optimization of Water Pumping and Injection for Underground Coal Gasification in the Meiguiying Mine, China

The Meiguiying mine is a famous underground coal gasification (UCG) mine in China, but there has been a potential safety hazard since it began operating, that groundwater in the overlying aquifer might enter the mine and even extinguish the gasifier. A 3-D hydrogeological model was developed to explore the characteristics of the seepage field of the aquifer and determine an optimal water pumping and injection option for the UCG. The results indicate that more attention should be paid to control induced fractures of the roof due to the increasing water level of the aquifer, and that a pumping rate of 160 m3/day would decrease the water level to a reasonable elevation. Moreover, to maintain the groundwater table and mine safety, 120 m3/day was recommended as a reasonable and economical recharge (re-injection) rate in the study area.

Characterizing interwell connectivity in waterflooded reservoirs using data-driven and reduced-physics models: a comparative study

Waterflooding is a significantly important process in the life of an oil field to sweep previously unrecovered oil between injection and production wells and maintain reservoir pressure at levels above the bubble-point pressure to prevent gas evolution from the oil phase. This is a critical reservoir management practice for optimum recovery from oil reservoirs. Optimizing water injection volumes and optimizing well locations are both critical reservoir engineering problems to address since water injection capacities may be limited depending on the geographic location and facility limits. Characterization of the reservoir connectivity between injection and production wells can greatly contribute to the optimization process. In this study, it is proposed to use computationally efficient methods to have a better understanding of reservoir flow dynamics in a waterflooding operation by characterizing the reservoir connectivity between injection and production wells. First, as an important class of artificial intelligence methods, artificial neural networks are used as a fully data-driven modeling approach. As an additional powerful method that draws analogy between source/sink terms in oil reservoirs and electrical conductors, capacitance---resistance models are also used as a reduced-physics-driven modeling approach. After understanding each method's applicability to characterize the interwell connectivity, a comparative study is carried out to determine strengths and weaknesses of each approach in terms of accuracy, data requirements, expertise requirements, training algorithm and processing times.

Robust optimization of subsurface flow using polynomial chaos and response surface surrogates

This study employs an inclusive framework for surrogate model-based optimization in the presence of parametric and spatial uncertainties. The framework is applied to optimize water injection rate for optimal hydrocarbon recovery from a synthetic subsurface model with uncertainty in the geological and fluid relative permeability properties. In one model of parametric uncertainty, geological properties such as the channel’s absolute permeability and the fault transmissibility multiplier and the fluid relative permeability parameters such as the residual oil saturation to water and the water relative permeability at residual oil are assumed to be non-informative. In another model, the channels positions are assumed uncertain and various realizations of the channelized permeability are parameterized and the spatial uncertainty is accounted for in the optimization. The uncertainty is quantified in each evaluation of the objective function via polynomial chaos expansions. The coefficients of polynomial chaos expansion are solved by probabilistic collocation method. The objective function is assigned with a risk-averse net present value computed from a distribution of values obtained from the probabilistic proxies. The proxies are updated for each round of objective function evaluation. Monte-Carlo simulations are also conducted to verify accuracy and to demonstrate the computational efficiency of the probabilistic collocation approach. The optimization is conducted in various random input cases (depending on the number of uncertain parameters) and for each case net present value is successfully maximized and optimal solutions of the water injection rates are determined.

A calculation method of optimal water injection pressures in natural fractured reservoirs

Abstract Injection pressures usually play a great role in the stimulation of low permeability fractured reservoirs. In this study, the stress state around an injection well was analyzed, and a three-collinear fracture model was established. Based on this model, the mode II fracture criterion was expressed in terms of a new form without stress intensity factor and fracture toughness involved. Based on this new form of fracture criterion, a calculation method of water injection pressures was proposed, and its effectiveness has been confirmed by the measurement results from Fuyu reservoir of Toutai oilfield. The factors that affecting optimal injection pressures have been investigated, and the results show that the water injection pressure is largely affected by the state of natural factures and the in-situ stress; According to Fuyu reservoir geological property and natural fracture distribution, the water injection pressure has been predicted and the result agrees well with that adopted in Fuyu reservoir. This study will have a beneficial application in the design and optimization of hydraulic fracturing in naturally fractured reservoirs.

Experimental study and numerical simulation of hydraulic fracturing tight sandstone reservoirs

Abstract Unconventional tight sandstone reservoirs have been developed during recent years and a large number of multi-stage fractured horizontal wells have been drilled to stimulate reservoir performance. However, fluid flow in low permeability porous media no longer obeys Darcy’s law and instead conforms to low-velocity non-Darcy flow. Most commercial numerical simulation software for multi-stage fractured horizontal well development may cause inaccuracy in simulating performance of tight sandstone reservoirs. In this paper, the investigation of existing conditions of low velocity non-Darcy flow for oil flow in irreducible water saturation tight sandstone cores was conducted and discussed through lab-experiments. And existence of low velocity non-Darcy flow was proven. Then, based on the low velocity non-Darcy flow model, the multistage fractured horizontal well numerical simulator was developed and verified. The comprehensive comparison and analysis of the simulation results of Darcy flow and non-Darcy flow were presented including liquid production rate, oil production rate, water cut, reservoir pressure, oil saturation distribution, and dimensionless permeability coefficient. With considering the non-Darcy flow, the fluid flow in reservoir consumes more driving energy and the water flooding efficiency was reduced. Finally, a multistage fractured horizontal well water injection pilot test in Fan-116 block was analyzed to perform the non-Darcy flow numerical study on an actual tight sandstone reservoir. The results show that for the tight sandstone reservoir, the optimal water injection time is when the average reservoir pressure declined to 26.92 MPa based on maximizing the total field oil production in 15 years. This pressure level is close to the hydrostatic pressure and the optimized recovery is 20.51% in the final simulation time. This approach is an initial exploration for the “multi-stage fractured horizontal well development for tight sandstone reservoirs considering non-Darcy flow” and could be applied to other tight oil/gas reservoirs.