Fracture Closure Pressure Research Articles

Hydraulic Fracture Closure Detection Techniques: A Comprehensive Review

This study reviews methods for detecting fracture closure pressure in both unconventional and conventional reservoirs using mathematical models and fluid flow equations. It evaluates techniques such as the Nolte method, tangent method, and compliance method. The investigation relies on observing changes in fluid flow regimes from preclosure to postclosure using fluid flow equations to examine the postclosure flow regime effect on the G function. Reverse calculations model pressure decline across synthesized flow regimes, facilitating a detailed investigation of the closure process. The analysis reveals that the tangent method is sensitive to postclosure fluid flow, while the compliance method is less effective in reservoirs with significant tortuosity or natural fractures. This paper recommends assessing natural fractures’ characteristics and permeability to identify the source of leak-off before selecting a technique. It proposes integrating various methods to comprehensively understand subsurface formations, combining their strengths for accurate fracture closure identification and a better understanding of subsurface formations. The new proposed workflow employs the continuous wavelet transform (CWT) technique for fracture closure detection, avoiding physical model preassumptions or simplifications to confirm the results. This approach offers guidance on selecting appropriate methods by integrating different techniques.

EXPERIMENTAL STUDY ON THE FRACTURE CONDUCTIVITY IN SHALE OIL PRODUCTION

Unconventional oil and gas resources, such as shale oil and gas, are gradually attracting great attention from all countries of the world. Horizontal drilling and large-scale hydraulic fracturing technology are used to efficiently extract oil from shale formation. Effective placement of the proppant in the fractures and high long-term conductivity are the keys to solve the problems of oil well flow rate increase in shale oil and gas fields. In this work, the sieve analysis method and FCMS-V fracture conductivity determination device, as well as scanning electron microscope are used. They are used to experimentally investigate the filtration characteristics of hydraulic fracturing fractures and establish the key factors affecting the filtration characteristics. The object of the study is the core of the oil-saturated DG shale formation of Songliao Basin. Also in this paper, the indentation and crushing mechanism of proppant under reservoir conditions is studied. The influence of various factors was evaluated qualitatively and quantitatively. The following studies were conducted: the effect of sand granule size on conductivity, the effect of grain size distribution on conductivity, the effect of proppant concentration on conductivity, the effect of fracture closure pressure on conductivity, and the effect of proppant indentation on conductivity. The granule sizes of the proppant used range from 30/50 to 70/140 mesh. Proppant concentration: 2,5; 5; 10 kg/m2. Ratios of granule sizes for used mixtures: 1:1:1, 1:2:7, 1:4:5.And crack clamping pressure from 20 to 40 MPa. As a result of the study, dependences of initial and long-term fracture conductivity on clamping pressure, granulometric composition of proppant and its concentration were obtained. Using a scanning electron microscope, the degree of indentation and crushing of proppant under reservoir conditions in two media, namely shale core and steel plates, was visually evaluated. The results of experimental studies can be used to optimize the shale oil development system and have scientific and practical significance for shale oil production in continental deposits.

Research on Hydraulic Fracturing Technology of Long Boreholes along Strata of High Vast Thick Coal Seam

Gas extraction is a major technique for regional gas regulation and coal and gas comining in China. Assuring effective gas extraction operations is a crucial step in ensuring the supply of energy. The effect range of extraction drilling, pressure relief degree, and standard period of gas extraction are all constrained because of the geological constraints affecting coal gas permeability and occurrence. Combined with the advantages of directional drilling and high-efficiency pumping technology and antireflection enhanced pumping technology of hydraulic fracturing, directional long-drilling hydraulic fracturing can effectively improve the efficiency of gas control and expand the scale of gas control. The present study focuses on the exploration of directional long-hole hydraulic fracturing technique in thick coal seams with high gas content using Dafosi Mine as a case study. The research findings demonstrate that hydraulic fracturing contributes to the enlargement of pore size, pore density, and pore connectivity in coal seams. In-depth research was conducted on the expansion of coal seam fractures during the hydraulic fracturing process using the RFPA3D-flow numerical simulation program. Additionally, a comprehensive analysis of stress distribution around the fractures under the flow-solid coupling condition was performed. To further improve the effectiveness of hydraulic fracturing technique, the research team optimized the fracturing tools and construction processes in the four coal seams of Dafosi Mine. The impact of segmented hydraulic fracturing in coal seam bare hole drilling was also studied. Furthermore, an investigation method specific to the coal seam bare hole segmented hydraulic fracturing effects applicable to Dafosi Mine was developed. The maximum fracture extension pressure, minimum fracture closure pressure, and fracture morphology change characteristics during drilling and fracturing were measured, and the fracturing influence radius of coal seam was determined to be 46−58 m, the gas extraction concentration after fracturing increased by 2.20–4.22 times, and the 100-m extraction flow increased by 4.93–11.03 times. It gives other mines technical assistance so they can keep advocating and utilizing the horizontal directional long-drilling stage hydraulic fracturing technique.

Analysis of Fracture Initiation Pressure of Tight Sandstone in HangJinQi

Simply increasing the fracture length to enhance the conductivity of the reservoir has limited success in increasing the production rate, thus hampering the pace of production at Hangjinqi. To combat this problem, a mathematical model was developed to determine the onset pressure of tight sandstone in Hangjinqi based on the Mohr-Coulomb criterion. It is shown that the onset angle decreases with increasing trap inclination, thus making it difficult to close the fracture with high horizontal pressure and suction. As for the block, it is one of Sinopec’s major areas for developing tight, low-permeability oil and gas in the Ordos Basin. To address this issue, a mathematical model was developed for the onset pressure of tight sandstone in Hangjinqi, taking into account factors such as vertical principal stress, maximum horizontal principal stress, minimum horizontal principal stress, and fracture inclination.The case of trap HE1 in JPH-416 was solved using a minimal bisection method, showing that the onset angle increases with trap inclination. As the fracture inclination increases, the fracture closure pressure gradually increases, and the effect of the minimum horizontal and vertical principal stresses becomes more pronounced.

Model and Analysis of Pump-Stopping Pressure Drop with Consideration of Hydraulic Fracture Network in Tight Oil Reservoirs

The existing pump-stopping pressure drop models for the hydraulic fracturing operation of tight oil reservoirs only consider the main hydraulic fracture and the single-phase flow of fracturing fluid. In this paper, a new pump-stopping pressure drop model for fracturing operation based on coupling calculation of the secondary fracture and oil-water two-phase flow is proposed. The physical model includes the horizontal wellbore, the fracture network and the tight oil reservoir. Through the numerical simulation and calculation, the wellbore afterflow performance, the crossflow performance between the main hydraulic fracture and the secondary fracture, the fracturing fluid leakoff and the oil-water replacement after termination of pumping are obtained. The pressure drop characteristic curve is drawn out by the bottom-hole flow pressure calculated through the numerical simulation, and a series of analyses are carried out on the calculated pressure drop curve, which is helpful to diagnose the -oil-water two-phase flow state and the fracture closure performance under the control of the fracture network after hydraulic fracturing pumping. Finally, taking a multi-stage fractured horizontal well in a tight oil reservoir in the Junggar basin, China as an example, the pump-stopping pressure drop data of each stage after hydraulic fracturing are analyzed. Through the history fitting of the pressure drop characteristic curve, the key parameters such as fracture network parameters, which include the half-length of main hydraulic fracture, the conductivity of main hydraulic fracture and the density of secondary fracture, the fracture closure pressure are obtained by inversion, thus, the hydraulic fracturing effect of fractured horizontal well in tight oil reservoirs is further quantified.

Diverting agents in the oil and gas industry: A comprehensive analysis of their origins, types, and applications

During the life of a well, treatments are carried out to boost productivity by stimulating initially unproduced zones. These treatments include hydraulic fracturing, matrix acidization, and acid fracturing, among others. Hydraulic fracturing treatment is generally applied to deeper reservoirs of oil or natural gas for enhanced recovery. By infusing proppant, water, and chemicals under extreme pressure during the fracturing procedure, fissures in and beneath the reservoir layer can be accessed and expanded. Another stimulating procedure, matrix acidization, involves injecting acid down the drilling hole to permeate the rock fissures at stresses lower than the fracture stress. In addition, carbonate reservoir acid fracturing stimulation is commonly used as an acid treatment technique whereby a pressure greater than the formation disintegration pressure or spontaneous fracture closure pressure is used to compress acid into the reservoir. These treatments allow existing wells to sustain hydrocarbon production without new wells being drilled. Diverters, when employed efficiently, can prevent the need to use a rig to provide momentary physical barriers, thus lowering the cost of the workover. Recent improvements in diversion technology make use of a variety of degradable particles that act as momentary bridges, either at the perforation entries or inside the existing fractures. The aim of this study is to introduce different types of mechanical and chemical diverters used to enhance the productivity of wells. This study explains the concepts of different types of diverters and their applications in several formations, it will also help readers to understand the selection procedures based on the suitability and requirements of diverter use by case studies from around the world.

Backstress Influence on the Formation Stress Field in Hydraulic Fracturing Experiments

This work presents an analysis of data obtained through unique laboratory experiments on hydraulic fracturing. In the experiments, sufficiently large artificial samples were used to model a reservoir. Thus, it was possible to simulate several wells simultaneously, given that hydraulic fracture was initiated in one of them. In addition, the setup construction provided a true triaxial stress–strain state. The setup allowed us to investigate parameters that are difficult to access in real conditions. The data processing based on six laboratory experiments on hydraulic fracturing showed discrepancies between the values of the minimum stresses calculated from the fracture closure pressure and the actual values known based on the experimental conditions. There was also a discrepancy between the theoretical values of the fracture breakdown pressure and those obtained through the experiments. This paper examines phenomena such as backstress as the main reasons for this discrepancy. Backstress is stress acting on the walls of a fracture or well and is caused by the filtered hydraulic fracturing fluid. The authors demonstrated that by taking into account this phenomenon, one can significantly reduce the differences between calculated and experimental values. Therefore, the authors call for the careful use of the standard theory when determining the stress state in real fields.

Validation of Estimating Stress from Fracture Injection Tests Using Continuous Wavelet Transform with Experimental Data

The article discusses the new technique for fracture closure pressure detection using continuous wavelet transform (CWT). The study focuses on calibrating the CWT technique and comparing it with different techniques for closure detection. According to the article, traditional methods for identifying the closure of hydraulic fracturing operations are based on assumptions that can conflict with one another, resulting in greatly varying approximations of closure pressure and duration. To address this issue, the article employs a set of diagnostic fracture injection tests that utilize the Step-Rate Injection Method for Fracture In-Situ Properties tool (SIMFIP). By directly observing wellbore deformation, the SIMFIP tool determines the minimum principal stress, while strain gauges monitor the opening and closing of fractures during multiple tests. The publicly accessible data are used to evaluate the accuracy of the new closure detection technique using CWT. The findings indicate that the CWT method aligns with measurements of deformation and can identify the impact of intricate closure events and pre-existing natural fractures. In conclusion, the article suggests that the CWT technique shows great potential as an alternative to traditional approaches for detecting closure pressure.

Study on coal seam physical characteristics and influence on stimulation: A case study of coal seams in zhengzhuang block

Coalbed Methane (CBM) is an unconventional form of natural gas which is self-generated and self-stored in coal seams. In order to realize the effective exploitation of CBM in Zhengzhuang block, microstructure, wettability, permeability, rock mechanics and in-situ stress of coal were studied in this research. It is found that high rank anthracite characterized by high vitrinite content and low inorganic mineral content, is abundant in CBM. More than 96% of inorganic minerals are clays dominated by kaolinite and illite. Various types of pores are developed on the coal. The wettability of coal differs from high to low to surface water, active water, and foam fracturing fluid; and contact angles of coal with active water and foam fracturing fluid decrease with the increase of burial depth. Gradients of fracture pressure and closure pressure in No.3 coal seam are higher than that of No.15 coal seam. The elastic modulus of coal is lower than that of sandstone. The construction curve of hydraulic fracturing shows that, when the construction flow rate and sand quantity are similar, the construction pressure of prepad in No.3 coal seam is lower than the pumping pressure of No.15 coal seam, but the propagated pressure is higher than that of No.15 coal seam. The drainage effect of No.3 coal seam with large pore volume, shallow burial depth and obvious fracture pressure is better than that of No.15 coal seam. The comprehensive understanding of coal physical properties and engineering practice in the block provide certain guiding significance to the CBM exploitation in Qinshui Basin.

A New Technique for Estimating Stress from Fracture Injection Tests Using Continuous Wavelet Transform

The diagnostic fracture injection test (DFIT) is widely used to obtain the fracture closure pressure, reservoir permeability, and reservoir pressure. Conventional methods for analyzing DFIT are based on the assumption that a vertical well is drilled in ultra-low permeability reservoirs with potential multiple closures but fails to consider horizontal wells. There is still significant debate about the rigorousness and validity of these techniques due to the complexity of the hydraulic fracture opening and closure process and assumptions of conventional fracture detection methods. The paper introduces a new method for detecting fracture closure pressure using the continuous wavelet transform (CWT). The new method aims to decompose the pressure fall-off signal into multiple levels with different frequencies using the CWT. This “short wavy” function is stretched or compressed and placed at many positions along the signal to be analyzed. The wavelet then convoluted the signal yielding a wavelet coefficient value. The signal energy is observed during the fracture closure process (pressure fall-off) and the fracture closure event is identified when the signal energy stabilizes to a minimum level. A predefined simple commercial fracture simulation case with known fracture closure, flow regime modeling, and actual field cases was used to validate the new methodology.

Use of flow-back and pressure rebound data improves the minimum stress estimation in a tight claystone formation

Andra is in charge of the long-term management of all radioactive waste in France. It has acquired between 2000 and 2008 a vast amount of stress data around the area selected to host the French deep geological repository for high activity and long-lived radioactive waste. The minimum principal stress was estimated from hydraulic fracturing tests and the fracture closure pressure was interpreted during the shut-in phase. However, in the Callovo-Oxfordian claystone, this method results in a minimum horizontal stress that is much larger than the vertical stress even when vertical fractures were clearly generated. As the uncertainty on the weight of the overlying sediments is low, the validity of this technique in a tight claystone formation with very limited leak-off is questioned. Several tests were reinterpreted using the flow-back data and the pressure rebounds when they were recorded. The new interpretation gives consistent results between the wells drilled around the Meuse/Haute-Marne underground research laboratory and the magnitude of the minimum principal stress matches well the actual orientation of the induced fractures. These data support the use of flowback tests as the preferred stress determination technique in tight formations.

A productivity prediction method for multi-fractured horizontal wells in tight oil reservoirs considering fracture closure

The closure fracture phenomenon increases the complexity of well testing and reduces the accuracy of productivity forecasts when tight oil reservoirs are exploited. However, most existing productivity models tend to ignore this. Therefore, a productivity prediction model for multi-fractured horizontal wells in tight oil reservoirs considering fracture closure has been developed by considering the stress sensitivity in the formation and combining the physical parameters of actual production. The model is solved by the Laplace transform, perturbation transform, Pedrosa transform, and Stehfest numerical inversion. Drawing productivity impact curves and discussing productivity influence factors based on the model results from this study show that the model is reasonable. In the actual production process, the hydraulic fracture parameter values are not as high as possible, and they have a reasonable range of values. The fracture closure pressure has a significant impact on the production of tight oil reservoirs. The higher the fracture closure pressure is, the greater the fracture conductivity decreases sharply, and the larger the proppant elastic modulus is, the stronger the fracture conductivity. The influence of fracture conductivity on the production in tight oil reservoirs has an obvious point, and when the value is less than the point, the production effect is good. Improved production can be achieved by balancing the relationship between fracture parameters. The findings of this study can help to better understand the influence of fracture parameters on productivity and contribute to increasing well production and improved development of tight oil reservoirs.

Rock-mechanical properties and in situ stress state of the Upper Cenomanian Mishrif limestone reservoir, Zubair oil field, southern Iraq

Rock-mechanical properties and tectonic stress state have crucial implications for reservoir stability, drilling, and production optimization. We have developed the first ever in situ stress analysis focused on the Mishrif reservoir from the supergiant Zubair oil field, southern Iraq. We interpreted an overall hydrostatic pore pressure gradient of 9.8 MPa/km and a vertical stress ([Formula: see text]) gradient of 22.17 MPa/km in the Upper Cenomanian Mishrif limestone formation. We inferred a Poisson’s ratio of 0.27–0.31, a Young’s modulus of 27–38 MPa, a coefficient of internal friction range of 0.66–0.76, and estimated a uniaxial compressive strength (UCS) range of 35–70 MPa with a low cohesive strength of 7.8–9.8 MPa from compressional sonic slowness data. We established fitting relationships between the dynamic and static elastic properties from the core-based triaxial test measurements and used the same for estimating the minimum ([Formula: see text]) and maximum ([Formula: see text]) horizontal stress magnitudes by poroelastic horizontal strain model. We validated the reservoir [Formula: see text] with the mini-frac-based fracture closure pressure and interpreted its gradient as 14.5–15.9 MPa/km, whereas we calculated the [Formula: see text] gradient as 19.5–23 MPa/km. We interpreted C-quality breakouts from four-arm caliper data and deciphered a northeast–southwest [Formula: see text] orientation (N45°E–N70°E). Using the compressive failure criteria, we constrained the reservoir [Formula: see text] by stress polygon analysis against the estimated UCS ranges and concluded a normal fault to strike-slip transitional tectonic stress state ([Formula: see text] ≥ [Formula: see text] > [Formula: see text]) in the Mishrif reservoir.

Complex Fracture Closure Pressure Analysis During Shut-in: A Numerical Study

Conventional fracture closure models typically assume homogeneous formation. This assumption renders complex fracture closure pressure analysis during shut-in insufficient at present. In this paper, we use a cohesive zone method (CZM)-based finite element model to obtain the fracture closure pressure and minimum horizontal principal stress of the major fracture and the branch fracture based on pressure fall-off analysis. Key factors including leak-off rate, injection time, and stress anisotropy are discussed in detail. A quantitative relationship between fracture closure pressure and these factors is plotted to reduce or eliminate the errors caused by conventional fracture injection diagnostic models. The results show that leak-off rate, injection time, and stress anisotropy have a significant effect on the fracture closure process. Fracture closure in naturally fractured formations is a slow process, and the early closure pressure represents the closure of the branch fracture, which is much higher than the minimum horizontal stress. This investigation provides new insight into how to estimate the in-situ stress in naturally fractured reservoirs.

Estimating the Least Principal Stress in a Granitic Rock Mass: Systematic Mini-Frac Tests and Elaborated Pressure Transient Analysis.

The hydraulic fracturing technique (also termed mini-frac test) is commonly used to estimate the in situ stress field. We recently conducted a mini-frac stress measurement campaign in the newly-established Bedretto Underground Laboratory (BedrettoLab) in the Swiss Alps. Four vertical boreholes, dedicated for stress characterization of the granitic rock mass, hosted a total of 19 mini-frac test intervals. Systematic pressure transient analysis was performed to carefully estimate the magnitude of the least principal stress (S_mathrm {3}). We compared five different methods (inflection point, bilinear pressure decay rate, tangent, fracture compliance, and jacking pressure) to identify an adequate approach best suited for our test scale and the host rock mass. We found that the methods used to determine the fracture closure pressure underestimate the magnitude of S_mathrm {3}, presumably due to the rapid closure of the hydraulic fracture after shut-in. The most consistent results were found using the inflection point and bilinear pressure decay rate method, which both determine the (instantaneous) shut-in pressure as the proxy for the S_mathrm {3} magnitude. The determined shut-in pressure, or S_mathrm {3} magnitude, is 14.6pm 1.4 MPa from the inflection point method. This allowed us to further estimate the stress environment around the BedrettoLab, which is transitional between normal and strike-slip faulting. The measured local pore pressures from extended shut-in periods are between 2.0 and 5.6 MPa, significantly below hydrostatic. A combination of drainage, cooling, and the excavation damage zone of the tunnel may have significantly perturbed the in situ stress field in the vicinity of the BedrettoLab.

Hydrofracture plugging mechanisms and evaluation methods during temporary plugging and diverting fracturing

AbstractTemporary plugging and diverting fracturing (TPDF) technique shows great advantages in stimulating unconventional oil and gas reserves. Revealing the fracture plugging mechanism and establishing the evaluation method are beneficial for revealing the mechanism of forming multiple fractures during TPDF. This work revealed the processes of plugging the fractures based on the typical injection pressure curve of hydraulic fracturing operation and then applied the stress cage model, the fracture closure stress model, and the fracture propagation resistance model to reveal the fracture plugging mechanisms. Moreover, this paper establishes a 2D XFEM model to evaluate the fracture plugging effect, and the reliability of the model is verified against the finite element model. Based on the XFEM model, this work investigates the fracture plugging effects influenced by the uneven distribution of net pressure within the fracture. The results prove that fracture mouth plugging of TPF mainly enhances the wellbore circumferential stress, in‐fracture plugging mainly enhances fracture closure pressure, fracture tip plugging mainly hinders fracturing fluids flowing toward fracture tips, all of them aim at enhancing the reopen pressure of the existing fractures and prevent the propagation of the existing fracture. Diverter bridging and plugging can change the distribution of fracture net pressure and dramatically reduce the fracture tip stress factor, and thus, the existing fracture propagation can be efficiently stopped.

Guest Editorial: Want To Learn Something New About DFITs? Start With an Old Book

Early in the development of unconventional reservoirs, the industry had little choice but to rely on the toolsets handed down from decades of conventional engineering practices. Later, new tools would be crafted in the hopes of better fitting the unconventional paradigm. This presents a choice to the technical community—rely on a traditional and proven method, or one designed for the unconventional system but less tested? Recently, many hydraulic fracturing engineers have been asking themselves this question when it comes to the diagnostic fracture injection test (DFIT). That includes myself, and the journey I took to find an answer culminated in a technical paper (SPE 206239) that was presented at the 2021 SPE Annual Technical Conference and Exhibition. What follows are some of that paper’s key findings which are being shared with the intent to further the discussion on best practices for those challenged with interpreting unconventional diagnostics. The paper utilizes the concept of permeability to validate traditional minimum stress interpretations across multiple reservoir conditions by comparing DFIT fracture closure time permeability estimates with core, pressure buildup, after-closure pressure, and rate transient analysis. This author was able to further support the results by the integration of a wide range of diagnostic technologies such as fiber optics, microseismic, and, among others, DFIT numerical inversions shared through eight case histories. Diagnostic Injections, a Long History Made Short One of the few ways to begin a conversation with a reservoir is by pumping treated fluid at fracturing rates and analyzing how the pressure falls off with time after the injection is stopped. The language for such dialogue and information exchange is formed by the dimensionless time function called “G-function” and was introduced by Ken Nolte in 1979. Nolte’s innovative postulations allowed our industry to determine the expected frac geometry, its conductivity, the formation flow capacity, and the optimum hydraulic fracture design as well as the means necessary to place the treatment. Recently introduced into industry literature is the proposed fracture closure pressure interpretation based on the fracture compliance method, interpreting an earlier, higher-stress estimation than estimates from well‑established methodologies. The practitioner is now faced with the dilemma of finding out which fracture closure interpretation technique is correct since this has a profound impact on how fracture geometry is modeled and optimized. To answer this question, a multibasin analysis of pre-frac tests from the Russia, North Sea, Europe, North Africa, and South America regions was undertaken.

Case Study: An Approach for Hydraulic Fracturing Minifrac G-Function Analysis in Relation to Facies Distribution in Multilayered Clastic Reservoirs

Summary An industry-accepted standard for minifrac analysis for evaluating and improving design of hydraulic fracturing treatments originated from the original Nolte analysis (Nolte 1979) of pressure decline, followed by the introduction of Castillo G-function in a Cartesian plot (Castillo 1987). The latter provides a graphical method for the identification of fracture closure pressures and stresses with subsequent derivation of other parameters such as fluid efficiency and fracture geometry. With the introduction of a more advanced consideration of the G-function interpretation for various reservoir conditions (Barree et al. 2007), subdividing the interpretation into calculations based on flow regimes and leakoff modes, this approach has become even more sophisticated. Particularly, interesting flow regimes and leakoff modes during fracture closure include the fracture height recession mode. This mode tends to result in rapid screenout and difficulty in placing high proppant concentrations. Regarding interpretation, the G-function derivative curve for this mode can have more than one plateau, an outcome that is possibly indicative of features that have not been widely considered to date or on which little to no data have been published. This paper presents a case study as an example of such height recession mode, along with a subsequent G-function interpretation and analysis and with consideration of the vertical facies distribution along the wellbore. Considerable attention is paid to the G-function derivative plateau analysis. Three distinctive wells, namely X-1, X-2, and X-3, are discussed. Using this technique can lead to an improved fracture calibration, optimized fracture design, and adoption of a successful completion strategy; additionally, the confirmation of 1D facies distribution can provide new insights into the fracture closure period.

Present-day stress field and stress path behaviour of the depleted Mishrif reservoir from the super-giant Zubair oilfield, Iraq – A geomechanical case study

Accurate understanding of the reservoir pore pressure and in-situ stress behaviour in response to depletion has critical effects in production optimization and field redevelopment while ensuring reservoir integrity. This work presents the first reservoir geomechanical modeling from the supergiant Zubair oil field, southern Iraq to decipher the pore pressure, in-situ stresses and depletion stress path of the middle Cretaceous Mishrif limestone reservoir. Vertical stress (Sv) has 0.97–0.99 psi/ft gradient. Minimum horizontal stress (Sh) estimated from effective stress ratio and Poisson's ratio-based approaches yielded an about 0.58–0.76 psi/ft gradient and validated with C-category fracture closure pressure data available from mini-frac tests. In absence of image log-based breakout widths, maximum horizontal stress (SH) is estimated from three approaches, which provided a gradient range of 0.89–1.21 psi/feet. Relative stress magnitudes (SH ≥ Sv >Sh) indicate a normal to strike-slip faulting transitional tectonic state in the study area. C-quality wellbore breakouts, interpreted from the oriented four arm caliper data infer a mean N60°E SH orientation, which is parallel to the movement direction of the Arabian plate towards the Eurasian plate. Recent downhole measurements indicate that the primary producer Mishrif limestone is in depleted condition. Stress path, interpreted from the reduction of pore pressure (Δpp) and minimum horizontal stress (ΔSh), yields average values of 0.65 and 0.62 for upper and lower Mishrif, respectively. Deformation analysis in reservoir space indicates stress path in depleted Mishrif formation of Zubair oil field is less than the normal faulting limit (0.71) and depletion-induced faulting is therefore unlikely to occur.

A new method for plugging the dominant seepage channel after polymer flooding and its mechanism: Fracturing–seepage–plugging

AbstractAfter polymer flooding, a low-resistant dominant seepage channel forms at the bottom of the high-permeability reservoir, which is extremely disadvantageous for further enhanced oil recovery. In this study, we proposed a new method to plug the dominant seepage channel after polymer flooding, through fracturing–seepage–plugging using a solid-free plugging agent, which can achieve deeper and further regional plugging. This method involved dissolving the crosslinking agent and stabilizer in the water-based fracturing fluid (hereinafter referred to as the fracturing plugging agent) and transporting it to the target reservoir through hydraulic fractures. The fracturing plugging agent percolated into the deep part of the reservoir under the action of fracture closure pressure and gelled with the residual polymer in the formation to achieve deep regional plugging of the advantageous channel. To study the percolation law of fracturing plugging agent in the dominant channel, high-pressure displacement experiments were conducted using natural cores under different permeability and concentration conditions of the fracturing plugging agent. The results showed that the percolation rate of the fracturing plugging agent was almost linearly related to reservoir permeability. Due to the formation of micro-fractures and crosslinking reactions, the percolation rate first increased and then decreased to a stable state. After a certain period, the pores were blocked, resulting in a sharp decrease in the percolation rate and then decayed. In addition, the higher the concentration of fracturing plugging agent, the better the core plugging performance. Moreover, when the concentration of fracturing plugging agent injected into the core exceeded 3,000 mg/L, the core permeability increased, and the breakthrough pressure evidently increased three to four times. On the basis of this, rheometer tests, scanning electron microscopy (SEM) observations, and mercury intrusion tests were performed to evaluate gelation performance, shear effect, and pore retention morphology of the crosslinking system made by mixing the injected plugging agent and residual polymer in the reservoir. The results showed that the shear action could reduce the gelling property, and the concentration of fracturing plugging agent should be >3,000 mg/L to meet the requirements of gelling. Furthermore, the viscosity of the crosslinking system reached the peak value at approximately 72 h, forming a network space structure of layered superposition, thereby increasing viscosity by 40–50 times. Finally, SEM images revealed that after the fracture plugging agent was injected into the core, the micelles were mostly concentrated in the front and middle sections. The average pore radius of the core decreased by 8.620 μm, and the average porosity decreased by 54.85%.