Improved Efficiency and Reliability of Hydraulic Fracture Modeling and Design with Standardized Stress Inputs for South Oil Fields in Sultanate of Oman

Hydraulic Fracturing (HF) is widely used in PDO in low permeability tight gas formations to enhance production. The application of HF has been expanded to the Oil South as conventional practice in enhancing the recovery and production at lower cost. HF stimulation is used in a number of prospects in the south Oman, targeting sandstone formations such as Gharif, Al Khlata, Karim and Khaleel, most of which have undergone depletion. Fracture dimension are influenced by a combination of operational, well design and subsurface parameters such as injected fluid properties, injection rate, well inclination and azimuth, rock mechanical properties, formation stresses (i.e. fracture pressures) etc. Accurate fracture pressure estimate in HF design and modeling improves reliability of HF placement, which is the key for improved production performance of HF. HF treatments in the studied fields provide large volumes of valuable data. Developing standardized tables and charts can streamline the process to generate input parameters for HF modeling and design in an efficient and consistent manner. Results of the study can assist with developing guidelines and workflow and for HF operations. Field HF data from more than 100 wells in south Oman fields were analyzed to derive the magnitude of breakdown pressure (BP), Fracture Breakdown Pressure (FBP), Instantaneous Shut-In Pressure (ISIP) pressure, and Fracture Closure Pressure (FCP) and develop input correlations for HF design. Estimated initial FCP (in-situ pore pressure conditions) is in the range of 15.6 - 16 kPa/mTVD at reservoir formation pressure gradient of about 10.8 kPa/m TVD bdf. However, most of the fields have undergone variable degree of depletion prior to the HF operation. Horizontal stresses in the reservoir decrease with depletion, it is therefore important to assess the reduction of FCP with reduction in pore pressure (stress depletion). Depletion stress path coefficient (i.e. change on FCP as a fraction of change in pore pressure) was derived based on historic field data and used to predict reduction of FCP as a function of future depletion. Data from this field indicates that the magnitude of decrease in fracture pressure is about 50% of the pore pressure change. Based on the data analysis of available HF data, standardized charts and tables were developed to estimate FCP, FBP, and ISIP values. Ratios of FBP and ISIP to FCP were computed to establish trend with depth to provide inputs to HF planning and design. Results indicate FBP/FCP ratio ranges between 1.24-1.35 and ISIP/FCP ratio ranges between 1.1 to 1.2. Developed workflow and standardized tables, charts and trends provide reliable predictions inputs for HF modeling and design. Incorporating these data can be leveraged to optimize parameters for HF design and modeling for future wells.

Integrated Hydraulic Fracturing Strategy Leads to Successful Execution of the First Highly Deviated Ultra-Deep Well in Tarim Oilfield

Well K1002 is the first highly deviated ultra-deep well in Tarim Oilfield of China, with the reservoir depth 7060m and the well deviation of 60° ∼ 77.6° in the fractured interval. Because of large deviation angle, high breakdown pressure and in-situ stress, poor effectiveness of natural fractures, large reservoir thickness, it is difficult and risky to implement hydraulic fracturing. In this paper, the fractured well was taken for a case study to illustrate the holistic optimization to guarantee the treatment success, a world-wide difficulty with high engineering risk. For figuring out a reasonable treatment design, comprehensive lab experiments and numerical simulation were conducted to analyze and benchmark the reservoir characteristics, rock mechanics and geological model. Systematic study on reducing breakdown pressure, development of natural fractures evaluation, multi-size combination of diverting agent, separated layer stimulation and fracture parameters optimization, treatment fluid formulation, proppant screening and operation program were carried out. Considering the wellbore trajectory and rock mechanics characteristics of well K1002, a breakdown pressure prediction model was established to optimize the perforation orientation. The best perforation orientation was 28° and 208°, the worst perforation orientation was 148° and 328°, and the breakdown pressure range was 168-175MPa with 60° phase angle. Combination with "imaging logging (0-3m) + far detection acoustic logging (0-30m) + geomechanics (0-300m)", the comprehensive evaluation and prediction of natural fractures in near wellbore area and far wellbore area were realized. Based on this, the stimulation technology of "mechanical layering + diverting agent" was optimized to connect the fracture development zone in near wellbore and far wellbore area. According to the Tight Packing Theory, the idea of "multi-size particles combination of diverting agent" was put forward. Through the experiment study, the combination of 1-5mm and 5-10mm particles was optimized, and the optimal chart of diverting agent size combination was made under different reservoir temperatures. For the fracturing job, totally 2562m3 KCL weighted fracturing fluid and 159.2m3 ceramic proppant of 40-70 mesh were pumped. The operation parameters were in reasonable agreement with the design. The initial test production was 10 times higher than before. The experience gained in this case study has some guiding significance for improving the success rate of hydraulic fracturing treatments in the highly deviated ultra-deep well and for effectively developing such fractured tight sandstone reservoirs, both theoretically and practically.

Rock Mechanical Properties and Breakdown Pressure of High-Temperature and High-Pressure Reservoirs in the Southern Margin of Junggar Basin

The mechanical properties of the high-temperature and high-pressure reservoirs in the southern margin of Junggar Basin have not been clearly understood, which correspondingly results in uncertainties when predicting the breakdown pressure. To address this issue, firstly, rock mechanical experiments under high temperature, high confining pressure, and high pore pressure were carried out. Secondly, empirical formulas related to the transformation of dynamic and static mechanical parameters in the regional strata were proposed. Finally, the existing prediction model for the formation breakdown pressure was improved by taking the wellbore seepage and thermal stress into consideration. Results show that under the reservoir condition of high temperature and high pressure, the rock sample tends to form closed shear cracks. High temperature causes thermal damages and the reduction of the compressive strength and elastic modulus, while the combined effects of high confining pressure and pore pressure enhance the compressive strength and plasticity of the rock sample simultaneously. Based on the correlation analysis, it is found that the static elastic modulus is linearly related to the dynamic value, while static Poisson’s ratio is a quadratic function of the dynamic value. These fitting functions can be used to obtain the profiles of static elastic modulus and Poisson’s ratio based on their dynamic values from the logging interpretation. Besides, the improved prediction model for the rock breakdown pressure can yield more accurate results indicated by the error less than 2%. Therefore, the proposed breakdown pressure prediction model in this study can provide theoretical guidance in the selection of fracturing truck groups and the design of the pumping schedule for high-temperature and high-pressure reservoirs.

Experimental Investigation on Hydraulic Fracture Morphology of Inter-Salt Shale Formation

The inter-salt shale in the Qianjiang formation of Jianghan Basin in China is characterized by multiple salt-shale bedding planes, various rock strength, and high heterogeneity of rock mechanics. In this paper fracturing experiments under different conditions were carried out to study the effects of the injection velocity, type of fracturing fluid and interface strength on the propagation law of hydraulic fracture in the salt sedimentary rhythm there. In the meantime, Acoustic emission system and radial strain sensor were applied to monitor experimental process. The result indicates that 1) compared with the shale, there are four fracture propagation modes mainly being observed: passivating type (Mode I), “I”-type (Mode II), penetration type (Mode III) and mixed type ((Mode IV)), among which the mixed type is the relatively complex crack propagation mode. 2) With the increase of injection rate and viscosity of fracturing fluid, the hydraulic fracture will penetrate cementation surface more easily. 3) The increase of flow rate and viscosity will increase the breakdown pressure. The breakdown pressure of high strength cementation surface is 16.70% higher than that of low strength.

Thermochemical-Pulse Fracturing of Tight Gas: Investigation of Pulse Loading on Fracturing Behavior

Unconventional and tight gas reservoirs are located in deep and competent formations, which requires massive fracturing activities to extract hydrocarbons. Some of the persisting challenges faced by operators are either canceled or non-productive fractures. Both challenges force oil companies to drill new substitutional wells, which will increase the development cost of such reservoirs. A novel fracturing method was developed based on thermochemical pressure pulse. Reactive material of exothermic components are used to generate in-situ pressure pulse, which is sufficient to create fractures. The reaction can vary from low pressure pulse, to a very high loading up to 20,000 psi, with short pressurization time. In this study, Finite Element Modeling (FEM) was used to investigate the impact of the generated pressure-pulse load, by chemical reaction, on the number of induced fractures and fracture length. Actual tests of pulsed fracturing conducted in lab scale using several block samples compared with modeling work. There was a great relationship between the pressure load and fracturing behavior. The greater the pulse load and pressurization rate, the greater the number of created fractures, and the longer the induced fractures. The developed novel fracturing method will increase stimulated reservoir volume of unconventional gas without introducing a lot of water to formation. Moreover, the new method can reduce formation breakdown pressure by around 70%, which will minimize number of canceled fracturing.

Engineering Charts for Predicting Breakdown Pressure for Finite-Length Wellbore Intervals

In wellbore drilling, the drilling mud density needs to be carefully selected such that the mud pressure inside the wellbore will not exceed formation breakdown pressure to avoid wellbore fracturing and extensive mud losses. However, in the hydraulic fracturing treatment, the lesser the value of the formation breakdown pressure the more optimal is the operation. We found out in this study that the pumping schedule (e.g., pumping duration and pumping rate) are factors in optimizing the breakdown pressure. In addition, this work investigates the effects of the finite length between packers on the magnitude of the breakdown pressure in various geological formations. The time-dependent evolving stresses around the wellbore are solved in the framework of time-dependent poroelasticity theory. The breakdown pressure is predicted from the evolution of the circumferential effective stresses. The effects of injection rate, formation properties, borehole diameter and length, and pumping duration on the breakdown pressure are presented in the form of engineering charts, for representative in-situ stress.

Core Scale FEM Modeling of Thermochemical Fracturing on Cement Cube Samples

Brownfields and depleting conventional resources of fossil fuel energy are not enough to fulfill the tremendously increasing energy demands around the globe. Unconventional oil and gas resources are creating a huge impact on the enhancement of the global economy. Tight rocks are usually located in deep and high-strength formations. In this study, numerical simulation results on a new thermochemical fracturing approach is presented. The new fracturing approach was implemented to reduce the breakdown pressure of the unconventional tight formations. The hydraulic fracturing experiments presented in this study were carried out on ultra-tight cement block samples. The permeability of the block samples was less than 0.005mD. Thermochemical fracturing was carried out by a thermochemical fluids that caused a rapid exothermic reaction which resulted in the instantaneous generation of heat and pressure. Different salts of nitrogen such as sodium nitrite and ammonium chloride were used as a thermochemical fluid. The instantaneous generation of the heat and pressure caused the creation of micro-cracks. The fracturing results revealed that the novel thermochemical fracturing was able to reduce the breakdown pressure in ultra-tight cement from 1095 psi to 705 psi. The reference breakdown pressure was recorded from the conventional fracturing technique. A finite element (FEM) analysis was conducted using commercial software ABAQUS. In FEM, two approaches were used to model the thermochemical fractures namely, cohesive zone modeling (CZM) and concrete damage plasticity models (CDP). The sensitivity analysis of peak pressure and time to reach the peak pressure is also presented in this study. The sensitivity analysis can help in better designing thermochemical fluids that could lead to the maximum generation of micro-cracks and multiple fractures.

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

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.

Thermally Controlled Fluid to Reduce Formation Breakdown Pressures in Tight Gas Reservoirs

High breakdown pressure is one of the major challenges in deep tight gas reservoirs. In certain wells, achieving breakdown pressures within the completion tubular yield limit is not possible, and those zones may have to be abandoned without fracturing. Using thermally controlled fluid can lower the formation temperature and ultimately reduce the stresses of the tight gas reservoir formation near the wellbore. The objective of this study is to prove numerically that having a cooled near-wellbore region is a feasible and effective solution to reduce the breakdown pressure. An integrated hydraulic fracturing and reservoir simulator that has been developed at the University of Texas at Austin is utilized for this study. The simulator is a non-isothermal, multi-phase black-oil flow in reservoir, fracture, and wellbore domains. It was found that using thermally controlled fluid is effective in reducing breakdown pressure. Bottomhole Pressure (BHP) decreased by up to around 60% when the temperature of the near-wellbore region is reduced by 60 °F under the simulated conditions in this study. Injecting thermally controlled fluid did not only reduce the high breakdown pressure but also improve the hydraulic fractures efficiency and complexity. This technique is novel and has not been studied in depth in the literature. Utilizing thermally controlled fluid can be a cost effective solution to reduce high breakdown pressure in tight gas reservoirs.

Investigation of Water Composition on Formation Damage and Related Energy Recovery from Geothermal Reservoirs: Geochemical and Geomechanics Insights

The main challenge in extracting geothermal energy is to overcome issues relating to geothermal reservoirs such as the formation damage and formation fracturing. The objective of this study is to develop an integrated framework that considers the geochemical and geomechanics aspects of a reservoir and characterizes various formation damages such as impairment of formation porosity and permeability, hydraulic fracturing, lowering of formation breakdown pressure, and the associated heat recovery. In this research study, various shallow, deep and high temperature geothermal reservoirs with different formation water compositions were simulated to predict the severity/challenges during water injection in hot geothermal reservoirs. The developed model solves various geochemical reactions and processes that take place during water injection in geothermal reservoirs. The results obtained were then used to investigate the geomechanics aspect of cold-water injection. Our findings presented that the formation temperature, injected water temperature, the concentration of sulfate in the injected water, and its dilution have a noticeable impact on rock dissolution and precipitation. In addition, anhydrite precipitation has a controlling effect on permeability impairment in the investigated case study. It was observed that the dilution of water could decrease formation of scale while the injection of sulfate rich water could intensify scale precipitation. Thus, the reservoir permeability could decrease to a critical level, where the production of hot water reduces and the generation of geothermal energy no longer remains economical. It evident that injection of incompatible water would decrease the formation porosity. Thus, the geomechanics investigation was performed to determine the effect of porosity decrease. It was found that for the 50% porosity reduction case, the initial formation breakdown pressure reduced from 2588 psi to 2586 psi, and for the 75% porosity reduction case it decreased to 2584 psi. Thus, geochemical based formation damage is significant but geomechanics based formation fracturing is insignificant in the selected case study. We propose that water composition should be designed to minimize damage and that high water injection pressures in shallow reservoirs should be avoided.