Fracture Geometry Optimization: Designs Utilizing New Polymer-Free Fracturing Fluid and Log-Derived Stress Profile / Rock Properties

2000 ◽  
Author(s):  
Brett Rimmer ◽  
Curtis MacFarlane ◽  
Chuck Mitchell ◽  
Henry Wolfs ◽  
Mathew Samuel
Keyword(s):  
Geometry Optimization ◽  
Rock Properties ◽  
Stress Profile ◽  
Fracturing Fluid ◽  
Fracture Geometry

Ability to Use DFIT to Replace the Minifrac in Sandstone Formations for Reservoir Characterizations

2021 ◽  
Author(s):  
Mohamed A. Gabry ◽  
Samuel A. Thabet ◽  
Emad Abdelhaliem ◽  
Ahmed Algarhy ◽  
Maharaja Palanivel
Keyword(s):  
Hydraulic Fracture ◽  
Reservoir Characterization ◽  
Deep Understanding ◽  
Good Method ◽  
Job Design ◽  
High Rate ◽  
Stress Profile ◽  
Fracturing Fluid ◽  
Reservoir Properties ◽  
Fracture Geometry

Abstract One of essential parts of hydraulic fracture job design optimization in deep sandstone formations is to conduct a minifrac test using fracture fluid to identify the closure pressure for calibration of the stress profile and to calibrate the leak-off coefficient of the fracturing fluid, but the test could not provide good understanding for reservoir properties of permeability, reservoir pressure, and intensity of natural fractures. By conducting the actual DFIT (Diagnostic Fracture Injection Test) and minifrac in more than thirty wells in different formations from different fields, several leak-off behaviors are observed and several conclusions can be reached by integrating minifrac, DFIT, geologic settings information, and production data. With the experience of conducting high rate and low rate DFIT before minifrac jobs, we can conclude that there are several benefits for the DFIT by replacing the minifrac, which conventionallyusesg a polymer fracturing fluid, with a non-wall-building fluid consisting mainly of water from the operations and job design perspective, and from the post frac production perspective. DFIT with water can introduce the best methodology to detect the induced complexity that may cause hydraulic fracture job cancellation in cases of detecting high complexity value early before rig movement. Implementing DFIT in a complete hydraulic fracturing design, execution and evaluation workflow can provide a deep understanding of the fracture geometry propagation and reservoir characterization. The main disadvantages of the DFIT is that it requires a long leak-off observation period but that can be minimized in the mD range of sandstone permeability. This paper introduces DFIT in sandstone formations as a good method for integration between the geology, reservoir management, and fracture operations. The paper provides the operational and integral benefits of replacing minifrac and fracturing fluid with DFIT and water in deep sandstone formations, which provides more accurate data analysis because testing is done with same fluid. In addition, it can reduce fracture operations cost by 10%.

Success Story of Optimizing Hydraulic Fracturing Design at Alpha Low-Permeability Reservoir

2021 ◽  
Author(s):  
Mario Hadinata Prasetio ◽  
Hanny Anggraini ◽  
Hendro Tjahjono ◽  
Aditya Bintang Pramadana ◽  
Aulia Akbari ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Oil Recovery ◽  
History Matching ◽  
Initial Period ◽  
Earth Model ◽  
Low Permeability ◽  
Stress Profile ◽  
Reservoir Pressure ◽  
Fracturing Fluid ◽  
Fracture Closure

Abstract This paper describes the evolution of the hydraulic fracturing approach and design in the Alpha reservoir over the past years. Alpha reservoir in XYZ field is a laminated sandstone reservoir with low permeability in the range of 20 to 140 md at a depth of approximately 4,000 to 4,500 ft true vertical depth (TVD). XYZ field is located in Rokan block, Riau, Central Sumatra region. Due to Alpha reservoir's nature, producing from this reservoir commercially requires stimulation. Hydraulic fracturing has been applied as the selected stimulation method to increase productivity from this reservoir. However, several challenges were recognized during the initial period, such as depleted reservoir pressure, indication of fracture height growth, and low to medium Young's modulus, which leads to few screened-out cases as well as low production gain after the fracturing treatment. The fracturing job in Alpha reservoir has been applied since 2002. However, pressure depletion was observed through this time until waterflood optimization started in May 2018 by converting commingled injection to injection dedicated to the Alpha reservoir. The pressure responded and increased from 350 psi to approximately 800 psi. Hence this reservoir still cannot be produced in single completion without the hydraulic fracturing job due to laminated reservoir and low-permeability character. A detailed look at the mechanical earth model (MEM) was done to revise the elastic properties and stress profile considering reservoir pressure change. The revised model was later used as an input for fracture geometry simulation. Calibration injection tests were performed and analyzed prior to the main fracturing treatments to determine fracture closure pressure and leakoff characteristics, which led to fracturing fluid efficiency. Results of these tests were used in job modifications regarding pad percentage, fracturing fluid rheology, proppant volume, and proppant concentration. Pressure history matching both after fracturing and in real time as well as the temperature log were used to validate the MEM and fracture geometries. Each change, approach, and impact were documented and statistically analyzed to determine a generic trend and design envelope for the Alpha reservoir. Between 2019 and 2020, nine wells were stimulated that specifically targeted the Alpha reservoir, with continuous improvement in fracturing design and geomechanics properties with each well. After fracturing, the 30-day oil recovery was superior, higher than previous fractured wells, reaching more than 255 BFPD on average. The successful development of the Alpha reservoir with hydraulic fracturing led to further milestones to maximize oil recovery in XYZ field.

Geomechanical Model as the Key Step to Proppant Fracturing Success in Shallow Carbonate Reservoir of Bahrain

2021 ◽  
Author(s):  
Ahmed AlJanahi ◽  
Feras Altawash ◽  
Hassan AlMannai ◽  
Sayed Abdelredy ◽  
Hamed Al Ghadhban ◽  
...  
Keyword(s):  
High Resolution ◽  
Horizontal Wells ◽  
Carbonate Reservoir ◽  
Rock Properties ◽  
Stress Profile ◽  
Geomechanical Model ◽  
Breakdown Pressure ◽  
Matrix Permeability ◽  
Geomechanical Analysis ◽  
Horizontal Strain

Abstract Geomechanics play an important role in stimulation design, especially in complex tight reservoirs with very low matrix permeability. Robust modelling of stresses along with rock mechanical properties helps to identify the stress barriers which are crucial for optimum stimulation design and proppant allocation. Complex modeling and calibration workflow showcased the value of geomechanical analysis in a large stimulation project in the Ostracod-Magwa reservoir, a complicated shallow carbonate reservoir in the Bahrain Field. For the initial model, regional average rock properties and minimum stress values from earlier frack campaigns were considered. During campaign progression, advanced cross dipole sonic measurements of the new wells were incorporated in the geomechanical modeling which provided rock properties and stresses with improved confidence. The outputs from wireline-conveyed microfrac tests and the fracturing treatments were also considered for calibration of the minimum horizontal stress and breakdown pressure. The porepressure variability was established with the measured formation pressure data. The geomechanically derived horizontal stresses were used as input for the frack-design. Independent fracture geometry measurements were run to validate the model. The poro-elastic horizontal strain approach was taken to model the horizontal stresses, which shows better variability of the stress profile depending on the elastic rock properties. The study shows variable depletion in porepressure across the field as well as within different reservoir layers. The Ostracod reservoir is more depleted than Magwa, with porepressure values lower than hydrostatic (∼7 ppg). The B3 shale layer in between the Magwa and Ostracod reservoirs is a competent barrier with 1200-1500psi closure pressure. The closure pressures in the Ostracod and Magwa vary from 1000-1500psi and 1100-1600psi, respectively. There is a gradual increasing trend observed in closure pressure in Magwa with depth, but no such trend is apparent in the shallower Ostracod formation. High resolution stress profiles help to identify the barriers within each reservoir to place horizontal wells and quantify the magnitude of hydraulic fracture stress barriers along horizontal wells. The geomechanical model served as a key part of the fracturing optimization workflow, resulting in more than double increase in wells productivity compared to previous stimulation campaigns. The study also helped to optimize the selection of the clusters depth of hydraulic fracturing stages in horizontal wells. The poroelastic horizontal strain approach to constrain horizontal stresses from cross dipole sonic provides better variability in the stress profile to ultimately yield high resolution. This model, calibrated with actual frac data, is crucial for stimulation design in complex reservoirs with very low matrix permeability. The geomechanical model serves as one of the few for shallow carbonates rock in the Middle East region and can be of significant importance to many other shallow projects in the region.

Experimental Study on Injection Pressure Response and Fracture Geometry during Temporary Plugging and Diverting Fracturing

SPE Journal ◽  
2020 ◽  
Vol 25 (02) ◽  
pp. 573-586 ◽  
Author(s):  
Bo Wang ◽  
Fujian Zhou ◽  
Chen Yang ◽  
Daobing Wang ◽  
Kai Yang ◽  
...  
Keyword(s):  
Injection Pressure ◽  
Fracture Network ◽  
Pressure Response ◽  
Hydraulic Fractures ◽  
Fracturing Fluid ◽  
Breakdown Pressure ◽  
Multiple Fractures ◽  
Differential Stress ◽  
Fracture Geometry ◽  
Stimulated Reservoir Volume

Summary Temporary plugging and diverting fracturing (TPDF) has become one of the fastest-growing techniques to maximize the stimulated reservoir volume (SRV). During the field operation of TPDF, diverters are injected to redirect the hydraulic fractures into the under-stimulated region of the reservoir, and, thus, to obtain better coverage of the created fracture network. In this study, the commonly used true tri-axial hydraulic fracturing system is modified to investigate the influences of various factors on the injection pressure response and resultant fracture geometry during diversion treatments. The experimental results show the feasibility of creating multiple fractures through TPDF, and more importantly give the following findings: (1) a complex diverted fracture network tends to be created at a small differential stress (2.5 MPa in this case), while diverted fractures tend to grow parallel to the initial fractures at a high differential stress (7.5 MPa in this case); (2) with the same concentration in the fracturing fluid, 40-mesh powder-shaped diverters can plug the created fractures and increase the net pressure more rapidly than 6-mm fiber-shaped diverters; (3) an excess of diverters can lead to a strong injection pressure response, and, thus, enhance the difficulty of creating multiple fractures; (4) when diverters are injected with the fracturing fluid, no obvious breakdown pressure or propagation pressure is shown during the fracture propagation.

Calculating far-field anisotropic stress from 3D seismic in the Permian Basin

2019 ◽  
Vol 38 (2) ◽  
pp. 96-105 ◽  
Author(s):  
Michael Shoemaker ◽  
Santhosh Narasimhan ◽  
Shane Quimby ◽  
James Hawkins
Keyword(s):  
Poisson’S Ratio ◽  
In Situ Stress ◽  
Poisson's Ratio ◽  
Rock Properties ◽  
Tight Oil ◽  
Far Field ◽  
3D Seismic ◽  
Stress Equation ◽  
Fracture Geometry

Minimum horizontal stress (Sh) is the controlling parameter when hydraulic fracture stimulating tight oil formations but is next to impossible to measure quantitatively, especially in the far field and away from the wellbore. In-situ stress differences between bedding planes control fracture containment, which defines the complexity of fracture propagation and fracture geometry including orientation, height growth, width, and length. Geomechanical rock properties define elastic behavior, influencing how the subsurface will deform under induced stress. These properties include dynamic and static Young's modulus, Poisson's ratio, and Biot's coefficient. When combined with pore pressure and overburden stress, the elastic rock properties describe the mechanical earth model (MEM), which characterizes the geomechanical behavior of the subsurface. The MEM also defines key inputs for calculating Sh using the Ben Eaton stress equation, which has been commonly used by geoscientists for decades. However, calculated Sh from this simple model historically produces uncertain results when compared to field-measured stress due to an assumed homogeneous and isotropic subsurface. This is particularly contrary to tight oil formations that represent shale (or mudrock) reservoirs that are highly laminated and therefore anisotropic. Optimal parameterization of fracture geometry models for well spacing and engineered treatment design requires an anisotropic far-field in-situ stress measurement that accurately captures vertical and lateral variability of geomechanical properties in 3D space. A method is proposed herein that achieves this by using a modified version of the anisotropic Ben Eaton stress model. The method calculates minimum Sh by substitution of inverted 3D seismic volumes directly into the stress equation, replacing the bound Poisson's ratio term with an equivalent anisotropic corrected closure stress scalar (CSS) term. The CSS seismic volume is corrected for anisotropy using static triaxial core and is calibrated to multidomain data types including petrophysics, rock physics, geomechanics, and completion and reservoir engineering field measurements.

Fracturing Fluid Design: A Closer Look at Breaker and Surfactant Selection

2021 ◽  
Author(s):  
Basil Alfakher ◽  
Ali Al-Taq ◽  
Sajjad Aldarweesh ◽  
Luai Alhamad
Keyword(s):  
Surface Tension ◽  
High Temperature ◽  
Ammonium Persulfate ◽  
Post Treatment ◽  
Berea Sandstone ◽  
Chemical Additives ◽  
Fracturing Fluid ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
Fracturing Fluids

Abstract Guar and its derivatives are the most commonly used gelling agents for fracturing fluids. At high temperature, higher polymer loadings are required to maintain sufficient viscosity for proper proppant carry and creating the fracture geometry. To minimize fracturing fluids damage and optimize fracture conductivity, it is necessary to design a fluid that is easy to clean up by ensuring proper breaking and sufficiently low surface tension for flow back. Therefore, breakers and surfactants must be carefully selected and optimally dosed to ensure the success of fracturing treatments. In this study, two fracturing fluids were evaluated for moderate to high temperature applications with a focus on post-treatment cleanup efficiency. The first is a guar-based fluid with a borate crosslinker evaluated at 280°F and the second is a CMHPG-based fluid with a zirconate crosslinker evaluated at 320°F. The shear viscosities of both fluids were tested with a live sodium bromate breaker, a polymer encapsulated ammonium persulfate breaker and a dual breaker system combining the two breakers. Different anionic and nonionic surfactant chemistries (aminosulfonic acid and alcohol based) were investigated by measuring surface tension of the surfactant solutions at different concentrations. The compatibility of the surfactants with other fracturing fluid additives and their adsorption in Berea sandstone was also investigated. Finally, the damage caused by leak-off for each fracturing fluid was simulated by using coreflooding experiments and Berea sandstone core plugs. Lab results showed the guar and CMHPG fluids maintained sufficient viscosity for the first two hours at baseline, respectively. The encapsulated breaker proved to be effective in delaying the breaking of the fracturing fluids. The dual breaker system was the most effective and the loading was optimized for each tested temperature to provide the desired viscosity profile. Two of the examined surfactants were effective in lowering surface tension (below 30 dyne/cm) and were stable for all tested temperatures. The guar broken fluid showed better regained permeability (up to 94%) when compared to the CMHPG (up to 53%) fluid for Berea sandstone. This paper outlines a methodical approach to selecting and optimizing fracturing fluid chemical additives for better post-treatment cleanup and subsequent well productivity.

High Accuracy Estimation of Hydraulic Fracture Geometry Using Crosswell Electromagnetics

2021 ◽  
Author(s):  
Shubham Mishra ◽  
Vinil Reddy
Keyword(s):  
Hydraulic Fracture ◽  
Horizontal Wells ◽  
Hydraulic Fractures ◽  
Calibration Data ◽  
Formation Water ◽  
Fracturing Fluid ◽  
Production Forecast ◽  
Fracture Geometry ◽  
Field Development ◽  
Well Completion

Abstract Unconventional resources, which are typically characterized by poor porosity and permeability are being economically developed only after the introduction of hydraulic fracturing (HF) technology, which is required to stimulate the hydrocarbon flow from these impermeable/tight reservoir rocks. Since 1960, HF has been extensively used in the industry. HF is the process of (1) injecting viscous gel fluids through the wellbore into the subterranean hydrocarbon formation, at high pressures sufficient enough to exceed tensile strength of the rock and hydraulically induce cracks/fractures (2) followed by injecting proppant-laden fluid into the open fractures and packing up the fracture with proppant pack, after the injected fluid leaks off into formation. The resultant proppant pack keeps the induced fracture propped open and thus creates a highly conductive flow path for the hydrocarbon to flow from the far-field subterranean formation into the wellbore. Most the modern wells in unconventional reservoirs are horizontal/near-horizontal wells that are completed with large multiple HF treatments across the entire length of the horizontal wellbore (lateral), to increase the reservoir contact per well. Productivity of these wells is dictated by the stimulated reservoir volume (SRV), which is dependent on the number of fractures and conductive hydraulic fracture surface area of each fracture that is propped open. Therefore, estimation of the hydraulic fracture geometry (HFG) dimensions has become very critical for any unconventional field development. Key dimensions are hydraulic fracture length, height, and orientation, which are required to assess the optimum configuration of fracturing, well completion, and reservoir management strategy to achieve maximum production. Designs can be assessed based on HFG observations, and infill well trajectories, spacing, etc. can be planned for further field development. This workflow proposes a method to estimate and model all or at least two parameters of HFG in predominantly horizontal or nearly horizontal wells by use of interwell electromagnetic recordings. The foundation of this workflow is the difference in salinity, or more precisely resistivity, of the fracturing fluid and the resident fluid (hydrocarbon or formation water). The fracturing fluid is usually significantly less resistive than the hydrocarbon that is the dominant resident fluid where fracturing is usually conducted, or less resistive than the formation water in case the HF occurs in high water saturation regions. Therefore, the resistivity contrast between the two fluids will demarcate the boundary of hydraulic fractures and thus help in precisely modeling some or all parameters of HFG. The interwell recordings can be interpreted along a 2D plane between the two wells, one of them bearing the transmitter and the other with the receiver. The interpretations along a 2D plane can be used to calibrate a 3D unstructured HF model, thereby introducing a reliable calibration input that did not exist before. There can be multiple such 2D planes as more than one well can have a receiver, and, in that case, the 3D HF model has more calibration data and is even more precise. The reason this workflow significantly improves precision in HFG estimation and modeling is that it provides the ability to demarcate only the open portion of the HF and not the entire volume where pumping fluid entered, which would include parts that closed too quickly to contribute to the production from the well. Today, the industry, by its best methods, can only see the entire rock volume that broke due to fracturing, although significant parts of that broken volume might not be contributing to the production and thus are irrelevant in the 3D models upon which important decisions such as production forecast and project economics are based.

Multi-Well Pressure History Matching in Delaware Play Helps Optimizing Fracturing for Subsequent Pads

2021 ◽  
Author(s):  
Roberto Suarez-Rivera ◽  
Rohit Panse ◽  
Javad Sovizi ◽  
Egor Dontsov ◽  
Heather LaReau ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
History Matching ◽  
Field Data ◽  
Field Measurements ◽  
Global Optimum ◽  
Rock Properties ◽  
Well Placement ◽  
Fracture Geometry ◽  
Conduct Sensitivity Analysis ◽  
Fracture Models

Abstract Predicting fracture behavior is important for well placement design and for optimizing multi-well development production. This requires the use of fracturing models that are calibrated to represent field measurements. However, because hydraulic fracture models include complex physics and uncertainties and have many variables defining these, the problem of calibrating modeling results with field responses is ill-posed. There are more model variables than can be changed than field observations to constrain these. It is always possible to find a calibrated model that reproduces the field data. However, the model is not unique and multiple matching solutions exist. The objective and scope of this work is to define a workflow for constraining these solutions and obtaining a more representative model for forecasting and optimization. We used field data from a multi-pad project in the Delaware play, with actual pump schedules, frac sequence, and time delays as used in the field, for all stages and all wells. We constructed a hydraulic fracturing model using high-confidence rock properties data and calibrated the model to field stimulation treatment data varying the two model variables with highest uncertainty: tectonic strain and average leak-off coefficient, while keeping all other model variables fixed. By reducing the number of adjusting model variables for calibration, we significantly lower the potential for over-fitting. Using an ultra-fast hydraulic fracturing simulator, we solved a global optimization problem to minimize the mismatch between the ISIPs and treatment pressures measured in the field and simulated by the model, for all the stages and all wells. This workflow helps us match the dominant ISIP trends in the field data and delivers higher confidence predictions in the regional stress. However, the uncertainty in the fracture geometry is still large. We also compared these results with traditional workflows that rely on selecting representative stages for calibration to field data. Results show that our workflow defines a better global optimum that best represents the behavior of all stages on all wells, and allows us to provide higher-confidence predictions of fracturing results for subsequent pads. We then used this higher confidence model to conduct sensitivity analysis for improving the well placement in subsequent pads and compared the results of the model predictions with the actual pad results.

A Better Well and Better Fracturing Improve Production in B-Field, Offshore Northwest Java

2021 ◽  
Author(s):  
Hendro Vico ◽  
Riezal Arieffiandhany ◽  
Indra Sanjaya ◽  
Lambertus Francisco ◽  
Yasinta Dewi Setiawati ◽  
...  
Keyword(s):  
Young’S Modulus ◽  
Simulation Analysis ◽  
Young's Modulus ◽  
Pressure Change ◽  
Production Performance ◽  
Rock Properties ◽  
Earth Model ◽  
Stress Profile ◽  
Fracture Conductivity ◽  
Wellbore Pressure

Abstract B-Field is located in Northwest Java and holds potential hydrocarbon in its low-quality marine sandstone reservoir, BR-34A and BR-34B zones. Each zone has a permeability range between 5 and 12 mD and can only produce approximately 20 to 50 BFPD without stimulation, making the well a non-economic producer. In 2020, two infill development wells, A-08 and K-08, were drilled targeting these zones. Both wells were planned to be completed with hydraulic fracturing stimulation to boost the production. The first well, A-08 was completed earlier than K-08, but the production result from the well was unsatisfactory. The pressure evaluation analysis indicated high near-wellbore pressure of more than 1,000 psi. There were no reliable mechanical properties data in the well, which led to a conservative final hydraulic fracture design to avoid fracture growth into the nearby watered-out zone, BR-35. Therefore, only 30,000 lbm of proppant were pumped, resulting in minimal proppant concentration in the pay interval for this reservoir of 360 lbm/ft even though the optimum amount of proppant for this type of reservoir is 1,000 lbm/ft. Limited proppant ramping concentration of only 6 PPA was also affecting proppant width around the wellbore, especially in this low Young's modulus reservoir. Because of this conservative design approach, the minimum target parameter from conductivity, dimensionless fracture conductivity, proppant concentration, does not meet optimum fracture half-length and skin. Eventually, the well could only produce 100 BFPD. A first application in the field of a comprehensive study of geomechanics using a sonic dipole log was performed to create a 1D mechanical earth model (MEM) on the second well, K-08, to validate the risk of breaking into the nearby water zone. In addition, this study was critical to confirm static rock properties and to revise the stress profile considering reservoir pressure change. As a result, it confirmed that the zones have enough competent shale barrier to hold the proppant volume according to the recommended design and that the zone has low Young's modulus (0.4 to 0.7 million psi) as well as lower stress compared to the preliminary estimation. A new technical approach then considered these additional facts to determine that a smaller proppant size with a larger amount of proppant would be optimal for maintaining width integrity and reducing the embedment effect. By using pressure evaluation software on the second well, better permeability and with less near-wellbore friction pressure were achieved. Later, a pressure match simulation analysis with optimum pad volume, larger volume of proppant, and higher proppant concentration resulted in a contained fracture in the zone of interest that did not break through the barrier into the watered-out BR-35 zone. Hence, the second well (K-08) has improved production performance with the well able to deliver over 500 BFPD.

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