Fractures In Low-permeability Reservoirs Research Articles

A Novel Fracturing Fluid Based on Functionally Modified Nano-Silica-Enhanced Hydroxypropyl Guar Gel.

Considering the damage caused by conventional fracturing fluid in low-permeability reservoirs, a novel fracturing fluid (FNG) combining hydroxypropyl guar (HPG) and functionally modified nano-silica (FMNS) was prepared. The properties of heat/shear resistance, rheological property, proppant transportation, and formation damage were evaluated with systematic experiments. The results showed that the viscosities of FNG before and after the heat/resistance were 1323 mPa·s and 463 mPa·s, respectively, while that of conventional HPG gel was 350 mPa·s. FNG is a pseudoplastic strong gel with a yield stress of 12.9 Pa, a flow behavior index of 0.54, an elastic modulus of 16.2 Pa, and a viscous modulus of 6.2 Pa. As the proportions of proppant mass in further sections transported with FNG were higher than those transported with HPG gel, FNG could transport the proppant better than HPG gel at high temperatures. Because of the amphiphilic characteristics of FMNS, the surface/interface properties were improved by the FNG filtrate, resulting in a lower oil permeability loss rate of 10 percentage points in the matrix than with the filtrated HPG gel. Due to the considerable residual gel in broken HPG gel, the retained conductivity damaged with broken FNG was 9.5 percentage points higher than that damaged with broken HPG gel. FNG shows good potential for reducing formation damage during fracturing in low-permeability reservoirs in China.

Effect of initial pore pressure on the hydraulic fracturing of tight sandstone: an experimental study

Pore pressure is a crucial factor affecting reservoir stimulation, especially in unconventional reservoirs, because it can control crack initiation and propagation. However, studies on the effect of initial pore pressure on hydraulic fracturing in low-permeability reservoirs are lacking, and fracturing mechanism remains unclear. Therefore, we conducted hydraulic fracturing tests under initial pore pressure, and proposed an improved fracturing initiation criterion to elucidate the fracturing mechanism of tight sandstone. The results demonstrated that the breakdown pressure increased with the initial pore pressure by 8 to 24%, and its evolution was identified approximately by the improved initiation criterion, which resulted in the complicated, invisible and intense features of the macroscopic fracture morphology and microscopic crack. The finding was mainly due to the viscous stress induced by fracturing disturbance under initial pore pressure and represented the dual interaction between rock structure and work fluid viscosity. As a result, the change in microporous diameter in micropores and a high pressure to failure can be obtained. Accordingly, the initial pore pressure in tight sandstone may not only induce n effective stress on the skeleton but also be responsible for the double effect on the fracturing mechanism with high pressure and intense failure features, which should be given attention in unconventional reservoir stimulation.

Investigation on Viscosity Behavior of Anionic Polyacrylamide Copolymer in Brine Solutions for Slickwater Fluids Applications at High Salinity and Hardness Conditions

Abstract Slickwater fluids, used to undertake fracturing in low-permeability reservoirs, may be derived from produced water consisting of a range of dissolved salts. The fluids are pumped downhole at high flowrates, and hence friction reducers, e.g., anionic polyacrylamides (APAMs) are added, which also impart viscosity to the fluid resulting in better proppant transport. The present work investigates the effect of an APAM copolymer on the viscosity of slickwater fluids; specifically, at high salinity and hardness conditions. The experimental part of this study demonstrated the impact of the parameters—APAM concentration and salt type/concentration—on slickwater fluid viscosity. In a freshwater–APAM fluid, as monovalent salt (salinity) is added incrementally, fluid viscosity decreased initially owing to the charge-shielding effect; and, then viscosity values were leveled off beyond a certain salinity level. However, a very peculiar behavior was observed for the addition of divalent salts (hardness) to fluid systems. Initially, as hardness increased up to 50k ppm (parts per million), as expected, fluid viscosity showed a significant decrease; on the contrary, as the hardness was raised beyond 50k ppm, the solution viscosity showed a distinctive increase up to 250k ppm. This phenomenon may be explained on the basis of the reverse charge-shielding effect, i.e., excessive divalent ionicity inducing repulsion between polymer charge sites. To model the above experimentally observed non-monotonous viscosity behavior, various machine learning models were employed; support vector regression (SVR)based models predicted the slickwater fluid viscosity with maximum accuracy. Sensitivity analysis was carried out to determine the prominence of the studied input parameters. The modeling work would assist in minimizing trial-and-error in designing/optimizing a slickwater fluid system.

Experimental investigation on plugging performance of nanospheres in low-permeability reservoir with bottom water

The oil production rate decreases rapidly after a short period of high yield from acidizing or fracturing in low-permeability reservoirs. In this paper, nanospheres are applied before the fracturing step, which possess the ability to absorb water and expand in the water layer, reducing the flow capacity of bottom water and finally enhancing the oil recovery. The plugging performance is investigated by nanosphere displacement experiments in cores and sand-packs, which explores the plugging effect in the oil layer, the oil-water transition zones, the water layer and the fracturing zones. In addition, a nuclear magnetic resonance experiment is conducted to study the flow mechanism of nanospheres and determine the plugging rates, which can characterize the plugging performance of nanospheres in porous media. The results show that the plugging rate is 85.84% and 78.65% on the water layer and oil-water transition zone, respectively, and 94.36% in the fracturing zone. Meanwhile, the nanospheres cannot plug the oil layer. The formation pressure has a less considerable effect on the plugging performance of nanospheres. The nanospheres have good injectivity, and the intensity variations in small, medium and large pores account for 34.46%, 13.22% and 52.32%, respectively. Overall, this paper explores the feasibility of applying nanospheres for water plugging and enhanced oil recovery. Cited as: Tang, M., Wang, C., Deng, X., Yang, H., Lu, J., Yu, H. Experimental investigation on plugging performance of nanospheres in low-permeability reservoir with bottom water. Advances in Geo-Energy Research, 2022, 6(2): 95-103. https://doi.org/10.46690/ager.2022.02.02

Production optimization and economic analysis for hydraulic fracturing operations in tight oil wells

A technical and economic analysis is done from simulations of propped hydraulic fracturing in low permeability reservoirs, as tight oil, in which the production from the well varies due to different well completion, each one is evaluated to determine the greatest economic performance. Working with a defined semi-integral system from the reservoir to the wellhead and focusing on well productivity; a method of analytic solution for diffusivity equation, alongside the nodal analysis method, and a multiphasic flow correlation for inclined tubing; allows estimating production on the wellhead. The cases studied demonstrate that hydraulic fracturing operations are very profitable before taxes, also, due to the high costs of these stimulation techniques, it is important to have an analytical tool that allows for a quick and precise evaluation of diverse scenarios, based on production analysis and its corresponding profit calculated by an economic analysis. This study could be adapted to analyze various tight oil reservoirs, providing results that justify investing in exploration and/or reactivation of them.

Планирование и анализ нагнетательных тестов при проведении гидроразрыва в низкопроницаемых пластах с применением ПК «РН-ГРИД»

Планирование и анализ нагнетательных тестов при проведении гидроразрыва в низкопроницаемых пластах с применением ПК «РН-ГРИД»

Flow physics of how surfactants can reduce water blocking caused by hydraulic fracturing in low permeability reservoirs

Significant amount of fracturing fluid is lost after hydraulic fracturing, and it is believed that the loss of fluid into the matrix can hinder the hydrocarbon production. One potential way to reduce this damage is to use surfactants. Robust surfactant formulations have been developed for chemical enhanced oil recovery (CEOR); similar screening methods are introduced in this study to reduce the water block in low permeability reservoirs. Here we present an experimental investigation based on a coreflood sequence that simulates fluid invasion, flowback, and hydrocarbon production within the rock near the fracture face. Real-time CT scans are applied to visualize the change of water saturation profile, which is then compared with the regaining of rock permeability. Different surfactants are used to test the effect of IFT reductions and formation of microemulsions; these are further compared in order to explore the best condition that maximizes the permeability enhancement. From this work, we recognize the main physical mechanism responsible for the potential enhancements after the use of surfactants, thus we suggest criteria to optimize the performance of surfactant additives for stimulating the low permeability gas/oil reservoirs.

Analytical model of the linear inflow to a horizontal well with hydraulic fractures in low-permeability reservoirs

At present, increasing attention has been concentrated on low-permeability deposits whose development is tightly related with technologies of horizontal drilling and hydraulic fracturing of the reservoir. However, the simultaneous presence of a horizontal section of the well and hydraulic fractures in the reservoir impedes the process of flow of reservoir liquids and gases through the porous medium and complicates simulation of such flows. In the present study a new analytical model of the linear inflow to a horizontal well with hydraulic fractures in low-permeability reservoirs is proposed. This is a generalizing model which takes into account both situations when there exists a linear flow in the direction perpendicular to the borehole of a horizontal well in the distant sections of the reservoir and when there is a linear flow in the direction parallel to the borehole of a horizontal well. The use of the model is not restricted by the shape of the flow domain. The new model proposed has a wide application field and does not require complex computations.

Waterflood Direction and Front Characterization With Four-Step Work Flow: A Case Study in Changqing Oil Field China

Summary Because of the effect of reservoir heterogeneity and fractures in low-permeability reservoirs, effective characterization of waterflood direction and front has become a challenging issue under high-water-cut condition. To achieve better understanding of such a complex problem, a work flow, containing statistical and numerical techniques, is developed to characterize waterflood direction and front distribution in Changqing oilfield by using both flow rates and bottomhole-pressure (BHP) data. The work flow includes four steps: First, dynamic analysis is used to qualitatively investigate the relationships between injector and producers; then, the constraint multiple-linear-regressions (MLR) method is applied to calculate the interwell-connectivity coefficients, which was used to quantitatively describe the waterflood direction by production and injection rates. On the basis of the results of the two former steps, we can adopt numerical well testing as our third step to deal with flow rates and BHP data to characterize the waterflood direction and front. Finally, the streamline method is used to simulate the waterflood front and high-permeability-channel distribution on the basis of the outcome of the three preceding techniques. Compared with individual methods, the proposed work flow can offer more perspectives and ways to make a comprehensive and deep investigation of the waterflood reservoir. The results obtained by this work flow enable proactive and better waterflood management in the Well Group W16 in Changqing oil field; namely, the water cut of producers decreases, meanwhile the oil production increases by nearly 40% referring to the field data in 2015. With the help of the information obtained by this work flow, operators could make more-reasonable decisions on waterflood management such as well-pattern optimization and injection–production parameters adjustment.

A new fracture prediction method by combining genetic algorithm with neural network in low-permeability reservoirs

Natural fractures in low permeability reservoirs are the dominant flow paths for the whole flow system. It is the difficult point to identify and predict natural fractures by using conventional logging data. Back propagation neural network is an effective method for natural fracture prediction, but it has the defect that convergence rate is slow and the objective function easily falls into the local minimum value. The genetic algorithm population search method can realize the optimal allocation if given network weights and threshold, which can improve back propagation neural network׳s defect of over-reliance on the gradient information and achieve the minimum global error. In this paper, by analyzing in-depth the relationship between observed fractures in the cores and well logging data, we proposed a new method of fracture identification in terms of deep-shallow laterolog curves as well as their amplitude difference and micro-electrode logging curves as well as its amplitude difference. The method was verified by oilfield dynamic monitoring data. In the application of the method to Xinli oilfield, the optimized standard samples were chosen to train the designed genetic algorithm back propagation neural network, and then the genetic algorithm-back propagation neural network for Xinli oilfield was established to predict fractures in the target reservoir. The prediction has good consistency with the oilfield׳s actual development performance, which proves the reliability of the new method.

Fracture Detection in Low-Permeability Reservoir Sandstone: Comparison of BHTV and FMS Logs to Core: ABSTRACT

Detection and characterization of fractures in low-permeability reservoirs is an important goal of reservoir analysis. Natural fractures may increase porosity in low-permeability rock and may enhance or limit the success of hydraulic fracture treatment. Two logging tools used for fracture detection are the borehole televiewer (BHTV), an acoustic device that maps the smoothness of the borehole wall, and Schlumberger's Formation Microscanner (FMS), a resistivity tool that produces a conductivity map of two 2.8-in. wide strips of the borehole wall. Their analysis compares BHTV and FMS logs to 1028 ft of core from three wells in the 2000-ft thick Lower Cretaceous Travis Peak Formation, a sandstone and shale unit that produces gas from low-permeability sandstone in east Texas. Core was obtained from depths of 5900 to 9900 ft. The Travis Peak provides a good test of fracture-imaging logs because natural fractures have complex geometry and variable mineral fill and because there are borehole breakouts, drilling-induced fractures, and vertical sedimentary structures that must be distinguished from natural fractures for successful fracture analysis.

Matrix Acidizing

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleum engineering. Introduction Many excellent and useful papers have been written on the subject of matrixacidizing. Included in this article is an extensive bibliography that should beuseful to the engineer in the design and execution of a matrix acidizing treatment in limestone or sandstone formations. The first matrix acidizing jobswere very successful in stimulating oil production in carbonates. However, mostof the recent attention to matrix acidizing concerns sandstones and the use ofvarious hydrofluoric acid systems. Matrix acidizing in carbonate formations still is beneficial in high-permeability, damaged formations (50 md or more). Damage can occur during drilling, completion or production of a well. Incarbonates with permeabilities less than 10 md, acid fracturing generally is used because much greater stimulation is obtained with long, acid-etched fractures in low-permeability reservoirs. Although the acid systems used insandstones and carbonates differ, the same practices apply to both. Well Performance (Need for Acidizing) Successful acidizing depends on the presence of damage and its location and intensity. The closer the damage is to the perforations, the more easily acidcan get to it. Compacted or crushed zone damage from perforating overbalancedcan be removed easily by acid, since only about 1/2 in. [1.3 cm] of damage mustbe removed directly around the perforation. Precipitates from previous acid treatments more than 1 ft [0.3 m] from the wellbore in sandstone or 5 ft [1.52m] in carbonate will be either impossible to reach with matrix acidizing or too expensive to treat. Deep solid plugging, will be corrected more effectively bycreating a conductive fracture through the damage either by sand fracturing oracid fracturing. Nonplugging damage (e.g., oil wetting) may be several feet deep around the wellbore, but reverse wetting surfactants can penetrate andreverse the formation to a water-wet condition at reasonable cost. Oil wetting damage usually is less severe than solid plugging damage, so correctivechemicals can reach the affected area easily. High-permeability formations (those with 100 md or more) seem to be dominated by either formation damage or tubing size flow restrictions. This is particularly true of gravel-packed offshore wells. When well flow is markedlyless than similar wells in the same reservoir, most of the drawdown probably isoccurring at the wellbore through a small zone of reduced permeability. Mostrecent gravel-pack-damage research has focused on gravel-packed tunnels andquality of the gravel in the tunnel. Current techniques have improved so muchin recent years that gravel-packed tunnels usually offer little flow resistance when perforating density is adequate. Nevertheless. reduced flow throughgravel-packed wells still occurs. Current research focuses onincompletely packed tunnels andformation-sand damage near the entrance to the tunnels. Torrest and Stein described gravel shifting in tunnels when the gravel pack is not packed tightly during placement. Damage to formation sand before gravelplacement will cause premature pressure outs resulting from viscous fluidsentering damaged or reduced permeability near the perforations. Because of highpressures, pumping may be halted before the gravel has concentrated adequately in the perforation tunnels. If the pumping stops too soon, the tunnels will befilled only partially with quality gravel. When the well is produced, formations and will enter the tunnels, bridging on the gravel inside the tunnel andpacking the partially void tunnel with formation sand, which is much lower inpermeability than the gravel. As the formation sand fills the tunnels. the pressure drop through the completion increases and the flow rate declines. JPT P. 2055^

Simulation of hydraulic fracturing in low-permeability reservoirs : Settari, A; Price, H S Soc Pet Engr JV24, N2, April 1984, P141–152

Simulation of hydraulic fracturing in low-permeability reservoirs : Settari, A; Price, H S Soc Pet Engr JV24, N2, April 1984, P141–152