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Collaborating Authors
Results
Evaluation of CO2 and Slickwater Fracturing for the Burgos Basin of Mexico
Silva-Escalante, C. F. (National Autonomous University of Mexico, UNAM, Mexico City, Mexico) | Camacho-Velazquez, R. G. (National Autonomous University of Mexico, UNAM, Mexico City, Mexico) | Gรณmora-Figueroa, A. P. (National Autonomous University of Mexico, UNAM, Mexico City, Mexico) | Sharma, Mukul M. (University of Texas at Austin, Austin, Texas, United States of America.)
Abstract This work aims to evaluate the fracture geometry and production scenarios comparing several fracturing fluids, such as slickwater and carbon-based fracturing fluids (CBFF), including two binary mixtures as approximations to anthropogenic CO2 resulting from carbon capture (oxyfuel, pre-combustion, and post-combustion). Reservoir flow modeling simulations show that CBFF is the best potential waterless fracturing fluid option for fracturing unconventional shale reservoirs in the Burgos Basin. We conducted fracturing simulations to obtain the fracture geometry resulting from pure CO2, gelled CO2, foamed CO2, as well as the binary mixtures CO2 (95% mol)-N2 (5% mol), and CO2 (95% mol)-H2 (5% mol) and compared the results to conventional slickwater fracturing. Data and information for this study come from a gas well in the Burgos Basin in Mexico. A compositional fracturing simulation model is used to obtain the fracture geometry and the conditions under which the CO2 fracturing would be optimal based on a sensitivity analysis of the critical parameters described in this work. We created a reservoir simulation model to generate production scenarios and compare the well performance of wells fractured with pure CO2 and slickwater. The impact of water blockage effects on well productivity is shown to be important. Results show that pure CO2, CO2-N2, and CO2-H2 create fracture geometries that are similar to slickwater fracturing. Pure CO2 provides the highest production due to the absence of water blockage effects. Other carbon-based fracturing fluids also represent an opportunity for implementing CO2 to optimize well performance reducing water blockage and water consumption for sustainably fracturing conventional and unconventional reservoirs.
- North America > United States > Texas (1.00)
- North America > Mexico > Tamaulipas (0.81)
- North America > Mexico > Nuevo Leรณn (0.81)
- North America > Mexico > Coahuila (0.81)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.72)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (10 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- (4 more...)
Tackling Breakdown and Proppant Placement Issues in a Deep, High-Pressure/High-Temperature Volcanic Reservoir: Lessons Learned Through Multistage Fracturing Campaigns in Minami-Nagaoka Gas Field, Japan
Kidogawa, Ryosuke (INPEX Corporation, Tokyo, Japan) | Yoshida, Nozomu (INPEX Corporation, Tokyo, Japan) | Kaneko, Masayuki (INPEX Corporation, Tokyo, Japan) | Takatsu, Kyoichi (INPEX Corporation, Tokyo, Japan) | Kubota, Ayumi (INPEX Corporation, Tokyo, Japan) | Boucher, Andrew (Fenix Consulting Delft BV, Delft, The Netherlands) | Shaoul, Josef (Fenix Consulting Delft BV, Delft, The Netherlands) | Tkachuk, Inna (Fenix Consulting Delft BV, Delft, The Netherlands) | Spitzer, Winston J. (Fenix Consulting Delft BV, Delft, The Netherlands) | De Pater, Hans (Fenix Consulting Delft BV, Delft, The Netherlands)
Abstract Fracturing treatments are often challenging in high-pressure/high-temperature, tectonically stressed areas with heterogeneous and complex lithology. This study presents case histories of two multistage fracturing campaigns executed on a tight gas formation in a deep volcanic reservoir onshore Japan. This work begins by highlighting the technical difficulties experienced during the first campaign, reviews the countermeasures developed over the course of the decade between campaigns, and finishes lessons learned from execution and evaluation of the second campaign. A root-cause analysis was undertaken to understand the poor treatment results from the first campaign where stages were defined by no formation breakdown, poor injectivity or early screen-out. It included re-evaluation of core/petrophysical interpretation, stress model and net pressure history matching, and development of injectivity index diagnostic plots. The findings were used to identify updated technologies and workflows for the second campaign with consideration of limitations in the target well drilled +10 years before and uncompleted. Finally, details of field execution and post-job logging results are presented to verify effectiveness of proposed techniques and extract lessons learned for future operations. The breakdown and injectivity issues of the first campaign appear to be tied to the initiation interval location and facies, where initiating in a massive lava facies was most problematic due to high stress and extreme tortuosity. Uncertainty in the propped height from the net pressure history matches showed room for optimization in treatment design. In the second campaign, with mitigation plans for breakdown issues, premature screen-outs and detection of propped height in place, nine fracture stages were attempted. Eight stages achieved successful breakdown with careful target selection and weighted brine. Two conventional treatments with crosslinked gel were placed in the intervals with high injectivity and, as a field trial, two slickwater treatments with high viscosity friction reducer were placed in intervals to deal with low injectivity. Issues with high apparent net pressure due to tortuosity continued, comparable to the first well, and efforts to further reduce treating pressure for future campaigns continues. Logging of the non-radioactive traceable proppant pumped revealed thin propped heights while production logging showed contribution from the zones treated with slickwater indicating it may be a viable solution for this type of challenging reservoir. This work highlights a series of technical issues and possible solutions of multistage fracturing in a volcanic reservoir, validated through field execution. Proposed solutions partially solved the challenges, but at the same time they open further questions for future campaigns. This study can serve as a reference for fracturing operations in challenging analogue reservoirs.
- North America > United States > Texas (1.00)
- Asia > Japan > Chลซbu > Niigata Prefecture (0.40)
- Overview (0.46)
- Research Report > New Finding (0.46)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Volcanology (0.91)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.46)
- North America > United States > Texas > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
- North America > United States > Louisiana > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
- North America > United States > Arkansas > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
- (9 more...)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics (1.00)
Summary This study focuses on the development of an analytical model to predict the long-term productivity of channel-fractured shale gas/oil wells. The accuracy was verified by comparing productivity calculated by the proposed model with numerical results. Sensitivity analysis was conducted to analyze significant parameters on the performance of channel fracturing. Field application of the model was conducted using production data obtained from an Eagle Ford Formation dry gas well, which was completed using channel fracturing. The procedure for estimating reservoir and stimulation parameters from production data was provided. The results indicated that the equivalent fracture width obtained from our model is consistent with the inversion of cubic law. Comparison with numerical simulations demonstrated that the proposed model might under- or overestimate well productivity, with mean absolute percentage error (MAPE) values of less than 8%. Sensitivity analysis indicated that, with the increase of fracture width, fracture half-length, and matrix permeability, the productivity of channel-fractured wells increases disproportionately. In addition, well productivity will increase as the ratio of the pillar radius to the length of channel fracture decreases, provided that the proppant pillars are stable and the fracture width is held constant. Under the conditions of smaller fracture width and larger matrix permeability, the effect of using channel fracturing to increase well productivity is more significant. However, as the fracture width becomes large, the benefits of channel fracturing will diminish. The case study indicated that the shale gas productivity estimated by the proposed model matches well with field data, with MAPE and R of 12.90% and 0.93, respectively. The proposed model provides a basis for optimizing the design of channel fracturing.
- South America (1.00)
- North America > United States > Texas (1.00)
- Europe (1.00)
- Asia (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline (0.89)
- South America > Argentina > Patagonia > Neuquรฉn > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Wyoming > Green River Basin > Jonah Field (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (18 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Modeling of Fracture Width and Conductivity in Channel Fracturing With Nonlinear Proppant-Pillar Deformation
Zhu, Haiyan (Chengdu University of Technology, State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, and Institute of Mechanics, Chinese Academy of Sciences) | Zhao, Ya-Pu (Institute of Mechanics, Chinese Academy of Sciences and University of Chinese Academy of Sciences) | Feng, Yongcun (University of Texas at Austin) | Wang, Haowei (Southwest Petroleum University) | Zhang, Liaoyuan (Sinopec Shengli Oilfield Company) | McLennan, John D. (University of Utah)
Summary Channel fracturing acknowledges that there will be local concentrations of proppant that generate highโconductivity channel networks within a hydraulic fracture. These concentrations of proppant form pillars that maintain aperture. The mechanical properties of these proppant pillars and the reservoir rock are important factors affecting conductivity. In this paper, the nonlinear stress/strain relationship of proppant pillars is first determined using experimental results. A predictive model for fracture width and conductivity is developed when unpropped, highly conductive channels are generated during the stimulation. This model considers the combined effects of pillar and fractureโsurface deformation, as well as proppant embedment. The influence of the geomechanical parameters related to the formation and the operational parameters of the stimulation are analyzed using the proposed model. The results of this work indicate the following: Proppant pillars clearly exhibit compaction in response to applied closure stress, and the resulting axial and radial deformation should not be ignored in the prediction of fracture conductivity. There is an optimal ratio (approximately 0.6 to 0.7) of pillar diameter to pillar distance that results in a maximum hydraulic conductivity regardless of pillar diameter. The critical ratio of rock modulus to closure stress currently used in the industry to evaluate the applicability of a channelโfracturing technique is quite conservative. The operational parameters of fracturing jobs should also be considered in the evaluation.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Asia > China (1.00)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug (0.46)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- North America > United States > Wyoming > Green River Basin > Jonah Field (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- (13 more...)
Abstract Study made from the results observed over a particular application objective with one of the recently developed proppant fracturing techniques known as Channel Fracturing. This technique was used in this application to place a proppant fracturing treatment in a tight gas reservoir which pushes the installed well completion to reach its mechanical limit capabilities. Channel (or pillar) fracturing was applied in multiple cases with the intention to constrain the pressure increase commonly observed during a fracture job execution.
- North America > Canada (0.68)
- Asia > Middle East > Saudi Arabia (0.47)
- North America > United States > Texas (0.29)
- North America > United States > Wyoming > Green River Basin > Jonah Field (0.99)
- North America > Mexico > Tamaulipas > Burgos Basin (0.99)
- North America > Mexico > Nuevo Leon > Burgos Basin (0.99)
- (2 more...)
Early Identification of a Potential Unconsolidated Reservoir and the Prevention of Sand Flowback by Incorporating a Liquid-Consolidation Agent with a Fracturing Treatment in Saudi Arabia
Hamid, Saad (Saudi Aramco) | Almulhim, Abdulrahman (Saudi Aramco) | Alabbad, Emad Abbad (Saudi Aramco) | Palanivel, Maharaja (Halliburton)
Abstract An engineering approach is discussed for identifying a potentially unconsolidated reservoir in an exploratory area and controlling sand flowback by fracturing using a liquid-consolidation additive as the binding agent. A vertical gas well targeting an exploratory reservoir was completed and hydraulically fractured to help enhance productivity. A petrophysical evaluation was performed with openhole logs, and results showed a potentially unconsolidated pay zone that posed the risk of producing formation sand. After identifying the issue, precautionary measures were taken to help prevent sand production. An engineered solution to hydraulically fracture the reservoir using a liquid-consolidating additive as a binding agent, opposed to the conventional resin-precoated proppant, was successfully performed. The fracturing technique enhanced well productivity and allowed sand-free high production rate of hydrocarbons. Orienting the perforations toward the maximum horizontal stress direction helped reduce tortuosity and placement of the fracturing treatment. This paper presents petrophysical analysis, treatment design, and application, including production analysis to evaluate the effectiveness of the treatment. Evaluation of the openhole logs and understanding the criteria for potential sand-producing formations can help identify sand flowback in the early stages of well completion to promote the application of solutions that will substantially reduce/eliminate problems associated with sand flowback during the life of the well. This technique helped achieve sand control without using screens, simplifying wellbore equipment while enhancing reservoir production. Early identification of the problem minimized production losses and non-productive time (days) for the operator and potential formation sanding problems.
- North America > United States (1.00)
- Asia > Middle East > Saudi Arabia (1.00)
- North America > Mexico > Tamaulipas > Burgos Basin (0.99)
- North America > Mexico > Nuevo Leon > Burgos Basin (0.99)
- North America > Mexico > Coahuila > Burgos Basin (0.99)
- Asia > Middle East > Saudi Arabia (0.91)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (2 more...)
Abstract Plug and Perf (PnP) has been predominant for years as the preferred completion method for unconventional reservoirs. However this technique can be costly and time consuming. The Coiled Tubing Activated Frac Sleeves (CTAFS) technique utilizes fracture sleeves that can be hydraulically opened using coiled tubing and fractured through the annuls, minimizing time between stages and reducing total fluid consumption. This paper evaluates the fracturing and production performance of the Plug and Perf technique compared to Coiled Tubing Activated Fracture Sleeves (CTAFS) in a US shale oil play (Eagle Ford) and in tight sand reservoirs (Cotton Valley, Bone Spring and Granite Wash). It focuses on a strategy of improving ultimate recovery by using fracturing modeling, proper completion selection and field data to determine the optimal stage spacing of the multistage completion systems (PnP and CTAFS). The fracture models were created using existing logs and geomechanical modeling results in the surrounding area to create an optimal geometric spacing for the stages. The basics of the primary multistage completion systems are discussed and briefly compared from an operations point of view. Effective fracture dimensions can be achieved by selecting better locations for the stage clusters in Plug ad Perf and single fracture injection points using Coiled Tubing Activated Frac Sleeves (CTAFS). Fracture treatment schedules for each completion technique are recommended in terms of proppant type, concentration, fracture fluid type and volume. Two different fracture treatments were used to analyze the effect of fracturing fluid and completion type on fracture geometry. Coiled Tubing Activated Frac Sleeves with an optimized fracture treatment schedule outperformed the PnP as it fully controls fracture placement, leading to bigger drainage areas. For PnP, cumulative production decreased with an increasing number of clusters and the less efficiency of the stages on productivity. Adding more sleeves accelerated the EUR because of a larger drainage area. The CTAFS technique allowed tighter spacing of frac stages and ensured that the fracture was created at the sleeve in contrast to PnP technique in which some zones could remain untreated.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.73)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.50)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Well Completion > Completion Selection and Design > Completion equipment (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- (3 more...)
Abstract The ongoing low oil price environment has profound impact on all the operators and service providers. Efficiency improvements and cost reductions are two key strategies to capture the opportunities in current situation. It is now imperative for engineers to improve engineering practices to gain efficiency and drive down the cost. However, in well stimulation practices, it is vital to all stakeholders to obtain fracturing fluids with desirable fluid viscosity, and thermal and chemical properties with cost as low as reasonably possible. Preparing fracturing fluids with high-hardness produced water is one option to drive down cost. Such a practice eliminates the need to transport fresh water and dispose wastewater. However, it may not be possible because of the reaction tendencies between cations and functioning polymers within fracturing fluids. Although combinations of chemicals including polymers, chemical additives, stabilizers, and buffers can be added to prevent such reactions, the dosages of each component are often hard to quantify and often dependent on the experience of field engineers. A fast prognosis tool has been developed to facilitate such a decision-making process by identifying the lowest possible dosages of chemicals dependent on produced water hardness. With such a prognosis tool, it is now possible to make more educated and cost-effective plans to optimize the engineering practice. In this work, the underlying physics of hard water damage to fracturing fluids is discussed, followed by a demonstration of the simulations that reproduced the lab rheology experiment results. The viscosity profiles of a number of rheology experiments were first matched as model calibrations. The effects of different stabilizers were then discussed by parametric comparison of different cases. With the predictive model successfully capturing the reaction system, a dynamic algorithm was built to compute the lowest cost possible solution of functioning fracturing fluids in a given system. Due to the non-linear nature of the chemical reaction system, a searching algorithm was implemented to minimize the cost of fracturing fluids as functions of local produced water hardness, cost of each chemical component and operational expenses. This work demonstrates that good engineering practices are achieved through carefully understanding and modeling a working system, and through dynamic planning of the overall workflow with cost optimization as a target. All in the form of a prognosis tool that could be easily implemented in the current fracturing fluid preparation work flow.
- North America > United States > Utah > Uintah Basin > Wasatch Formation (0.99)
- North America > Mexico > Tamaulipas > Burgos Basin (0.99)
- North America > Mexico > Nuevo Leon > Burgos Basin (0.99)
- North America > Mexico > Coahuila > Burgos Basin (0.99)
Optimization of Chock Valves for Fracture Clean-up in Tight Gas Condensate Reservoirs
Zhang, Kai (University of Calgary) | Liu, Qingquan (University of Calgary) | Wang, Kun (University of Calgary) | Jing, Gary (University of Calgary) | Zhang, Shihan (University of Calgary) | Zhan, Jie (University of Calgary) | Wu, Keliu (University of Calgary) | Chen, Shengnan (University of Calgary) | Chen, Zhangxin (University of Calgary)
Abstract Hydraulic fracturing is a vital technique to unlock tight gas condensate reservoirs. The efficiency of clean-up in tight gas condensate reservoirs has a tremendous effect on well delivery. During hydraulic fracturing flowback operations, only part of fracturing fluids flows back to the surface, resulting in discrepancies between the expected fracture length and the effective production fracture length. A reasonable choke size during fracture clean-up can help to maximize the fracture conductivity. In order to get a maximum amount of fracturing fluids flowing back to the surface and a least amount of proppants flowing back, optimization of a chock valve in operations is investigated. Furthermore, effects of a proppant size and well types including vertical and horizontal wells on chock valve adjustments are presented. A chock is adjusted by gradually increasing its diameter as fractures start to close. In addition, the chock size needs to be bigger in a horizontal well than that in a vertical well under the same conditions. If the fracture width close to a proppant size, the chock size will be bigger as the proppant diameter increases; if the fracture width is much larger than the diameter of the proppants, the chock size will be larger with a larger diameter of proppants prior to fracture closure. However, the optimum chock size will be smaller with a larger size of proppants after fracture closure.
- North America > Mexico > Tamaulipas > Burgos Basin (0.99)
- North America > Mexico > Nuevo Leon > Burgos Basin (0.99)
- North America > Mexico > Coahuila > Burgos Basin (0.99)
- (13 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
Abstract Preparing fracturing fluids from low-quality water such as hard water is an environmentally friendly option in field operations and is therefore highly desirable. However, fluid viscosity can be significantly reduced when mixed in hard water rather than fresh water, requiring the addition of stabilizers to mitigate the hardness damages. Although some stabilizers have already been identified in experiments, systematic studies to help optimize fracturing fluids based on chemical compositions of produced water and the chemical properties of polymer and stabilizers are still needed. In this work, we use reactive transport model to understand how stabilizers mitigate water hardness damages in fracturing fluids prepared with hard water. We studied a system where several stabilizers have been proved to mitigate hard water damages to metal-crosslinked derivatized polysaccharide (MCDP) fracturing fluids. Reversible chemical reactions between MCDP and cations lead to polysaccharide salts precipitations that compromised the fluid viscosity. Stabilizers are chemically active substances that preferentially react with cations, especially divalent cations so they can protect MCDP from precipitating. To benchmark this system, reactive transport models were set up to explicitly consider the fluid viscosity alterations caused by the chemical reactions among polymers, cations and stabilizers in flow conditions relevant to regain conductivity tests (RCT). The numerical simulator was developed based on Crunchflow with the viscosity as a function of polymer and cation concentration. The viscosity profiles of a number of rheology experiments were first matched as model calibrations. The effects of different stabilizers were then determined by parametric comparison of different cases. The model was then verified by matching it to the rheology of fracturing fluids prepared in experiments by mixing MCDP and stabilizers with hard water samples. Simulation results show that the type of stabilizers and cations in the hard water has a significant impact on the viscosity alteration for the same level of MCDP added. Stabilizers mitigate the hardness damages either instantly or in a latent manner depending on their intrinsic reaction kinetics with cations. This work demonstrates that reactive transport model could be used to help design and optimize fracturing fluids according to laboratory tests and produced water compositions. It is believed to be the first time that reactive transport modeling is used to study the complicated interactions among polymers, cations and stabilizers in fracturing fluids.
- Research Report > New Finding (0.35)
- Research Report > Experimental Study (0.35)
- North America > United States > Utah > Uintah Basin > Wasatch Formation (0.99)
- North America > Mexico > Tamaulipas > Burgos Basin (0.99)
- North America > Mexico > Nuevo Leon > Burgos Basin (0.99)
- North America > Mexico > Coahuila > Burgos Basin (0.99)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics (1.00)