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

2022 ◽  
Author(s):  
Ruqaiya Al Zadjali ◽  
Sandeep Mahaja ◽  
Mathieu M. Molenaar
Keyword(s):  
Pore Pressure ◽  
Stress Path ◽  
Pressure Change ◽  
Injection Rate ◽  
Production Performance ◽  
Path Coefficient ◽  
Variable Degree ◽  
Breakdown Pressure ◽  
Fracture Pressure ◽  
Fracture Closure

Abstract 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.

A Novel Method and its Application to Define Maximum Horizontal Stress and Stress Path

2021 ◽  
Author(s):  
Jianguo Zhang ◽  
Karthik Mahadev ◽  
Stephen Edwards ◽  
Alan Rodgerson
Keyword(s):  
Fracture Initiation ◽  
Stress Path ◽  
Horizontal Stress ◽  
Geomechanical Model ◽  
Breakdown Pressure ◽  
In Situ Stresses ◽  
Fracture Closure ◽  
Minimum Horizontal Stress ◽  
Maximum Horizontal Stress

Abstract Maximum horizontal stress (SH) and stress path (change of SH and minimum horizontal stress with depletion) are the two most difficult parameters to define for an oilfield geomechanical model. Understanding these in-situ stresses is critical to the success of operations and development, especially when production is underway, and the reservoir depletion begins. This paper introduces a method to define them through the analysis of actual minifrac data. Field examples of applications on minifrac failure analysis and operational pressure prediction are also presented. It is commonly accepted that one of the best methods to determine the minimum horizontal stress (Sh) is the use of pressure fall-off analysis of a minifrac test. Unlike Sh, the magnitude of SH cannot be measured directly. Instead it is back calculated by using fracture initiation pressure (FIP) and Sh derived from minifrac data. After non-depleted Sh and SH are defined, their apparent Poisson's Ratios (APR) are calculated using the Eaton equation. These APRs define Sh and SH in virgin sand to encapsulate all other factors that influence in-situ stresses such as tectonic, thermal, osmotic and poro-elastic effects. These values can then be used to estimate stress path through interpretation of additional minifrac data derived from a depleted sand. A geomechanical model is developed based on APRs and stress paths to predict minifrac operation pressures. Three cases are included to show that the margin of error for FIP and fracture closure pressure (FCP) is less than 2%, fracture breakdown pressure (FBP) less than 4%. Two field cases in deep-water wells in the Gulf of Mexico show that the reduction of SH with depletion is lower than that for Sh.

Experimental Investigation of Reservoir Stress Path Hysteresis During Production-Injection Periods

2014 ◽  
Author(s):  
Mojtaba P. Shahri ◽  
Stefan Z. Miska
Keyword(s):  
Pore Pressure ◽  
Poisson’S Ratio ◽  
Stress Path ◽  
Horizontal Stress ◽  
Poisson's Ratio ◽  
Injection Process ◽  
Fracture Pressure ◽  
Industry Standards ◽  
Depletion Period ◽  
Stress Changes

There has been an increasing consciousness regarding stress changes associated with reservoir depletion as the industry moves towards more challenging jobs in deep-water or depleted reservoirs. These stress changes play a significant role in the design of wells in this condition. Therefore, accurate prediction of reservoir stress path, i.e., change in horizontal stresses with pore pressure, is of vital importance. In this study, the current stress path formulation is investigated using a Tri-axial Rock Mechanics Testing Facility. The reservoir depletion scenario is simulated through experiments and provides a better perspective on the currently used formulation and how it’s applicable during production and injection periods. The effect of fluid re-injection into reservoirs on the horizontal stress is also analyzed using core samples. According to the results, formation fracture pressure would not be equal to its initial value if pressure builds up using re-injection. The irrecoverable formation fracture pressure has a power law relation with pore pressure drawdown range. In order to avoid higher permanent fracture pressure reduction, it’s recommended to start the injection process as soon as possible during the production life of reservoirs. According to the experimental results, rocks behave differently during production and injection periods. Poisson’s ratio is greater during pressure build-up as compared to the depletion period. According to the current industry standards, Poisson’s ratio is usually obtained using fracturing data; i.e., leak-off test or mini-fracture test, or well logging methods. However, we are not able to use the same Poisson’s ratio for both pressure drawdown and build-up scenarios according to the experimental data. Corresponding to Poisson’s ratio values, the change in horizontal stress with pore pressure during drawdown (production) is higher than during build-up (injection) period. The outcomes of this study can significantly contribute to well planning and design of challenging wells over the life of reservoirs.

On the undrained unloading behaviour of gassy sands

2009 ◽  
Vol 46 (11) ◽  
pp. 1267-1276 ◽  
Author(s):  
A. Amaratunga ◽  
J. L.H. Grozic
Keyword(s):  
Pore Pressure ◽  
Effective Stress ◽  
Marine Sediments ◽  
Stress Condition ◽  
Saturation Pressure ◽  
Stress Path ◽  
Pressure Change ◽  
Dissolved Gas ◽  
Total Stress ◽  
Dissolved Form

Soils that contain large amounts of dissolved gas within the pore fluid are called gassy soils. Gassy soils are common in marine environments and it is important to further our understanding of the unloading behaviour of gassy soils because of their potential to initiate and propagate submarine slope failures. This paper focuses on the pore-pressure responses and volumetric strains of loose gassy sands under different undrained unloading stress paths in laboratory specimens. Special attention was given to the constant deviatoric stress (q-constant) undrained unloading stress path as it simulates the stress condition imposed by tidal drawdown — one of the potential triggers of landslides in gaseous marine sediments. Gas exsolution was observed when the pore pressure was reduced below the liquid gas saturation pressure. Upon further decreases in total stress, the resulting pore-pressure change was much less than the total stress change; hence, effective stress decreased rapidly and at a certain point the samples tested under the q-constant stress path collapsed. This paper has experimentally and theoretically shown that gas in free and (or) dissolved form is detrimental in undrained unloading stress paths.

A Novel Approach for Estimating Formation Permeability and Revisiting After-Closure Analysis of Diagnostic Fracture-Injection Tests

SPE Journal ◽  
2019 ◽  
Vol 24 (04) ◽  
pp. 1809-1829 ◽  
Author(s):  
HanYi Wang ◽  
Mukul M. Sharma
Keyword(s):  
Pore Pressure ◽  
Radial Flow ◽  
Transient Behavior ◽  
Injection Rate ◽  
Natural Fracture ◽  
Well Test ◽  
Field Development ◽  
Flow Capacity ◽  
Special Cases ◽  
Fracture Closure

Summary Estimating reservoir-flow capacity is crucial for production estimation, hydraulic-fracturing design, and field development. Laboratory experiments can be used to measure the permeability of rock samples, but the results might not be representative at a field scale because of reservoir heterogeneity and pre-existing natural-fracture systems. Diagnostic fracture-injection tests (DFITs) have now become standard practice to estimate formation pore pressure and formation permeability. However, in low-permeability reservoirs, after-closure radial flow is often absent and this can result in significant uncertainties in interpreting DFIT data. In addition, the established methods for analyzing DFIT data make two oversimplified assumptions: Carter leakoff and constant fracture compliance (or stiffness) during fracture closure. However, both assumptions are violated during fracture closure; therefore, G-function-based models and subsequent related work can lead to an incorrect interpretation and are not capable of consistently fitting both before- and after-closure data coherently. Moreover, current after-closure analysis relies on classic well-test solutions with a constant injection rate. In reality, a “constant injection rate” does not equal “constant leakoff rate into the formation,” because more than 90% of the injected fluid stays inside the fracture at the end of pumping instead of leaking into the formation. The variable leakoff rate clearly violates the constant-rate boundary condition used in existing well-test solutions. In this study, we extend our previous work and derive time-convolution solutions to pressure-transient behavior of a closing fracture with infinite and finite fracture conductivity. We show that the G-function and the square-root-of-time models are only special cases of our general solutions. In addition, we found that after-closure linear-flow and bilinear-flow analysis can be used to infer pore pressure reliably but fail to estimate other parameters correctly. Most importantly, we present a new approach to history match the entire duration of DFIT data to estimate formation-flow capacity, even without knowing closure stress and the roughness properties of the fracture surface. Our approach adds significant value to DFIT interpretation and uncertainty analysis, especially in unconventional reservoirs where the absence of after-closure radial flow is the norm. Two representative field cases are also presented and discussed.

Stress Path Analysis of the Depleted Middle Miocene Clastic Reservoirs in the Badri Field, Gulf of Suez Rift Basin, Egypt

2021 ◽  
Author(s):  
Ahmed E. Radwan ◽  
Souvik Sen
Keyword(s):  
Path Analysis ◽  
Pore Pressure ◽  
Middle Miocene ◽  
Stress Path ◽  
Horizontal Stress ◽  
Gulf Of Suez ◽  
Normal Faulting ◽  
Future Production ◽  
Uniaxial Compaction ◽  
Rate Optimization

Abstract The purpose of this study is to evaluate the reservoir geomechanics and stress path values of the depleted Miocene sandstone reservoirs of the Badri field, Gulf of Suez Basin, in order to understand the production-induced normal faulting potential in these depleted reservoirs. We interpreted the magnitudes of pore pressure (PP), vertical stress (Sv), and minimum horizontal stress (Shmin) of the syn-rift and post-rift sedimentary sequences encountered in the studied field, as well as we validated the geomechanical characteristics with subsurface measurements (i.e. leak-off test (LOT), and modular dynamic tests) (MDT). Stress path (ΔPP/ΔShmin) was modeled considering a pore pressure-horizontal stress coupling in an uniaxial compaction environment. Due to prolonged production, The Middle Miocene Hammam Faraun (HF) and Kareem reservoirs have been depleted by 950-1000 PSI and 1070-1200 PSI, respectively, with current 0.27-0.30 PSI/feet PP gradients as interpreted from initial and latest downhole measurements. Following the poroelastic approach, reduction in Shmin is assessed and reservoir stress paths values of 0.54 and 0.59 are inferred in the HF and Kareem sandstones, respectively. As a result, the current rate of depletion for both Miocene reservoirs indicates that reservoir conditions are stable in terms of production-induced normal faulting. Although future production years should be paid more attention. Accelerated depletion rate could have compelled the reservoirs stress path values to the critical level, resulting in depletion-induced reservoir instability. The operator could benefit from stress path analysis in future planning of infill well drilling and production rate optimization without causing reservoir damage or instability.

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