
 Deep exploration and gas wells with very tight formations to be hydraulically fractured in the Sultanate of Oman, have been preferably perforated with Abrasive Jet perforating systems in order to reduce the perforating skin and to be able to break down the formation compared to the regular deep penetration shaped charges which historically have been unsuccessful used. The complexity of the Abrasive Jet perforating operations requires Coil Tubing, Sand Management System (SMS), specialized perforator BHA, correlating devices, pumping and mixing equipment and a substantial quantity of fluids and sand per interval.
 Perforating guns with reactive liner technology, conveyed with electric line, have been considered for these types of wells. This technology delivers enhanced perforations facilitating fracturing operations by reducing the break down pressures. Initially well data from three exploration wells "A", "B" and "C" were extensively evaluated with very high chances to succeed. The job execution was planned parallel to the Abrasive Jet perforation in case the formation would have not broken down after the gun perforations. In well "A" two stages were executed successfully using the reactive liner shape charge technology while in the well "B" the first stage was neither broke down after reactive liner charges nor after Abrasive Jet perforations; the second stage in well "B" was successfully executed after the reactive shape charge gun perforations. This initial success of these two exploration wells was replicated in another gas field also with tight formations which historically has been perforated with Abrasive Jetting near well "C".
 As a result of this, the efficiency, the perforating accuracy and the cost savings are substantial improved; the HSE exposure is much less due to the fact that less resources are needed compared to the requirements for Abrasive Jet. This paper will go thru the design, planning, execution, results and the big step change in the fracturing operations in these types of wells in which Abrasive Jetting is not always the best preferred option.

Reactive Liner Perforating Technology used to Improve Efficiency of Hydraulic Fracturing Operations

The horizontal stress profile plays an important role, extending from wellbore stability analysis to well completion optimization of tight gas reservoirs. When considering exploration fields with planned wells being drilled to 5500-m TVD, it is imperative to quantify tectonic effects at the well location. In addition, accurately predicting stress profile and fracture initiation values in vertical wells is required to identify sweet zones and barriers. This paper presents the details of a pre-fracture geomechanical model using breakouts and advanced acoustic data for post-fracture analysis. The analysis contains a history match of fracture initiation pressure, which consider the effects of filter cake around permeable sand, variation in tensile strength, and quantification of horizontal stress contrast in the different fields. Overall, three reservoirs have been analyzed, each containing more than eight wells with operations history. Core tests were used to calibrate dynamic-to-static rock elastic and mechanical properties, both of which reduced uncertainty in the model. The poroelastic horizontal strain method was used to build a continuous stress profile. Typically, the rock fabric found in the cores, images, and anisotropy data from the three reservoirs is different and required various dynamic-to static conversions. The Aeolian deposits-based reservoir has a wide variation in horizontal stress, and fracture height is typically governed by the stiffness of the layers. The lower permeability zones have relatively higher tensile strength, compared with higher permeability zones leading to relatively higher fracture initiation values. Overall, the ratio of maximum horizontal stress-to-minimum horizontal stress varies between 1.20 and 1.28 based on post-fracture analysis, which correlates well with regional tectonics and structural data. Depending on lithological variation and structure changes, the horizontal strain component varies at the layer level within regional tectonics. Inversion of fracturing data helped to constrain horizontal strain and stress variations in the field.

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Constraining tectonic components during a geomechanics-aided successful hydrofracturing campaign of tight gas exploration field

In the process to add more reserves, exploration wells are being drilled targeting unconventional tight gas at depth intervals of 4500m-5300m TVD. With limited dataset available in structure, high quality borehole images and far field acoustic measurements at high temperature are key to build stress profile in tight reservoir. This paper describes how geomechanical study ranging from wellbores stability to critical stressed fractures was integrated into the decision- making process during perforation design and upcoming well design. The geomechanical studies supported the successful zone selection for perforation and frac along with reservoir quality. The geomechanical modeling helped to understand presence of breakouts and drilling induced fractures in alternate layers drilled with same mud weight under thermal stress effect. The Geomechanics model with rock mechanical properties and stress profile was built using dipole sonic, borehole images, mud logs, leak-off tests and drilling records. Examination of the borehole images showed presence of breakouts and drilling induced fractures in alternate thin layers. Drilling induced features were prominent more in relatively higher GR layers across borehole than breakouts, with maximum percentage at start of drilling open hole section near reservoir top. Most of the breakouts were present in lower GR layer with lower rock strength. Layers with lower Poisson’s Ratio were common with drilling induced fractures and presence of natural fractures. These fractures were analyzed to check if they were critically stressed. Cooling effect due to temperature difference between mud and borehole wall at start of drilling was used in the wellbore stability calculations. Minimum horizontal stress direction was found to be N45Edeg which is just at 90deg offset to regional geological setting. This has been confirmed with fast shear azimuth direction in low GR layer with stress induced anisotropy. The geomechanical data guided several critical decisions in perforation design: most of the layer with natural fractures and drilling induced fractures are critical stressed and hence, should be chosen to perforate and frac bounded by stress barriers. Mud weight used during drilling was higher than required to avoid shear failures, hence percentage of drilling induced features over borehole length is higher than breakouts seen in alternate layer of lower strength. Difference of temperature in early drilling stage resulted in thermal stressed induced tensile failures and later with thermal equilibrium enhanced breakouts due to higher compressive stress. Possible fault was interpreted with change in stress azimuth near one reservoir unit with absence of stress barrier using MEM near water zone at deeper depth. Engineered with the integrated geological and geomechanics information, perforation jobs have been performed successfully with very good testing results optimizing initial depth intervals. Note: This paper was accepted into the Technical Program but was not presented at IMAGE 2022 in Houston, Texas. 

Rock mechanics characterization using borehole images and far field acoustic measurements to optimize perforation in unconventional reservoir


 In an unconventional reservoir exploration process, the horizontal stress profile across different rock types plays a critical role for drilling and frac design optimization. Present study provides insight about the challenge of estimating stress profile and breakdown pressure in tight sandstone gas reservoirs at 4900m-5500m TVD with varying petrophysical parameters across a complex geological setting. A geomechanical model is prepared prior to a hydraulic fracturing job based on open hole geophysical logs and history match borehole images features like breakouts and drilling induced fractures. Advanced sonic shear fast & slow radial profiles are inverted to directly estimate horizontal stress profile in applicable formations to constrain strain at different well locations. This helps to map changes in stress magnitude, contrast and direction in reservoir across different exploration areas. Algorithm has been successfully implemented earlier worldwide in deep water and has been tested successfully in tight shallow sandstone where dispersion data shows crossover of fast & slow shear near wellbore due to hoop stress. 3D anisotropic data from advanced sonic measurement has been utilized to predict true rock fabric based rock mechanical, elastic and stress profile in silty layers. It helps to understand containment of frac across different reservoirs and optimize stages. Rock types based on petrophysical results, image features and estimated breakdown pressure were used as reference for choosing frac stages. Post-frac closure and breakdown pressure values came close to estimated values using geomechanical results and provided confidence in strain values at different fields. Breakdown pressure seems to vary in range of 12500 psi to 19000 psi depending on stress and rock quality for same reservoir. Stress barrier at top of one reservoir vary at various locations as confirmed with tracer and pressure history match which was predicted using geomechanical model. This integrated petrophysical-geomechanics workflow has been utilized in two vertical wells for two reservoirs successfully to understand field level variation in closure and breakdown pressure and map degree of anisotropy with geological variation. Cost effective optimization of Frac design have been achieved through proper integrated approach saving rig time in decision making and avoiding extra stage as confirmed through Tracer logs.

Mapping Stress Profile and Rock Quality Variation in Tight Gas Sandstone Across a Geological Setting


 The field under study is witnessing an increasing trend in NPT events while drilling vertical wells through high stressed shale formations and the underlying depleted sandstone reservoir in the same section. The field has multiple sets of faults with lateral variations in stress azimuth and completion quality with the regional strike-slip regime. High angled wells are being planned to increase reservoir coverage and perform hydro fracturing. This paper provides details of capturing stress regime variation along with the effects of depletion in offset wells and identify suitable azimuth of planned well with drilling risks through a 3D geomechanical study. Comprehensive 1D mechanical earth models are constructed using open hole logs, core data and available hydro-fracturing results for wells in the field. Rock mechanical properties have been calibrated at well scale as per core data. Poro-elastic horizontal strain method at well scale indicates a strike-slip to reverse fault variation with significant horizontal stress anisotropy as evident from the closure pressure range of 9,500 psi to 12,500 psi. 3D numerical geomechanical model has been constructed considering structural discontinuities, rock mechanical properties and formation pressure to estimate the principal stresses. Stress direction data from dipole sonic measurements and breakout azimuth from borehole image logs are used for calibration in 3D model incorporating faults. Stress path for depletion has been estimated. Results from the study suggested change in casing policy specifically to have a liner isolating the overburden formations where more than 800 m should be drilled prior to entering the depleted reservoir formation. 3D geomechanical analysis reckons that the mud weight should be in the range of 12.7 kPa/m to 13.1 kPa/m during building up the well profile at 80 deg inclination in overlying shale while 1D study suggesting a range of 13.2 kPa/m to 13.7 kPa/m. Along well path at 80deg to 90deg deviation within reservoir layer toward minimum horizontal stress azimuth, mud weight requirement was found to be much lower at 11.5 kPa/m to 12.1 kPa/m. Apart from mud weight, BHA and chemicals were optimized to avoid differential sticking and better hole cleaning for respective sections. Actual mud weight used was in the range of 12.8 kPa/m to 13.1 kPa/m for building up with no torque and drag issue while running liner and BHA trips. Mud weight was maintained in the range of 11.5 kPa/m to 11.8 kPa/m in the horizontal section with minimum breakouts and smoother hole condition. Cuttings shape and size analysis were performed regularly to check well behavior and manage downhole pressure higher than shear failure limit. Using 3D Geomechanical study and continuous monitoring of drilling parameters in near real-time, the buildup and reservoir sections have been drilled within schedule with no major NPT event and saved at least one week of rig days.

Redha Hasan Al Lawatia

Papers

Mapping Stress Profile and Rock Quality Variation in Tight Gas Sandstone Across a Geological Setting

Successful Drilling Campaign of High Angled Wells in Tight Gas Fields using 3D Geomechanical Modeling and Real-Time Monitoring

Integrated Workflow for MicroFrac Analysis Using MDT Dual-Packer Operation Data: Case Study from Oman