The Ostracod formation in the Awali brownfield is an extremely challenging layer to develop because the tight carbonate rock is interbedded with shaly streaks and because of the presence of a nearby water-bearing zone. Although the Ostracod formation has been in development since 1960, oil recovery has not yet reached 5% because past stimulation attempts experienced rapid production decline. The current project incorporated aggressive fracture design coupled with a unique height growth control (HGC) workflow, improving the development of Ostracod reserves. The HGC technology is a combination of an engineering workflow supported by geomechanical modeling and an advanced simulator of in-situ kinetics and materials transport to model the placement of a customized, impermeable mixture of particles that will restrict fracture growth. The optimized treatment design included injections of the HGC mixture prior to the main fracturing treatment. This injection was done with a nonviscous fluid to improve settling to create an artificial barrier. After the success of a trial campaign in vertical wells, the technique was adjusted for the horizontal wellbores. The high clay content within the Ostracod layers creates a significant challenge for successful stimulation. The high clay content prevents successful acid fracturing and leads to severe embedment with conventional proppant fracturing designs. We introduced a new approach to stimulate this formation with an aggressive tip-screenout design incorporating a large volume of 12/20-mesh proppant to obtain greater fracture width and conductivity, resulting in a significant and sustained oil production gain. The carefully designed HGC technique was efficient in avoiding fracture breakthrough into the nearby water zone, enabling treatments of up to 450,000 lbm to be successfully contained above a 20-ft-thick shaly barrier with small horizontal stress contrast. Independent measurements proved that the fracture height was successfully contained. This trial campaign in vertical wells proved that the combination of aggressive, large fracture designs with the HGC method could help unlock the Ostracod’s potential. Three horizontal wells were drilled and simulated, each with four stages of adjusted HGC technique to verify if this aggressive method was applicable to challenging sand admittance in case of transverse fractures. This rare implementation of HGC mixtures in horizontal wells showed operational success and proof of fracture containment based on pressure signatures and production monitoring. The applied HGC technique was modified with additional injections and improved by advanced modeling that only recently became available. These contributed to a significant increase of treatment volume, making the jobs placed in the Ostracod some of the world’s largest utilizing HGC techniques. The experience gained in this project can be of a paramount value to any project dealing with hydraulic fracturing near a water formation with insufficient or uncertain stress barriers.

The Ostracod formation in the Awali brownfield is an extremely challenging layer to develop because the tight carbonate rock is interbedded with shaly streaks and the presence of a nearby water-bearing zone. Although the Ostracod formation has been in development since 1960, oil recovery has not yet reached 5% because past stimulation attempts experienced rapid production decline. The current project incorporated aggressive fracture design coupled with a unique height growth control (HGC) workflow, improving the development of Ostracod reserves. The HGC technology is a combination of an engineering workflow supported by geomechanical modeling and an advanced simulator of in-situ kinetics and materials transport to model the placement of a customized, impermeable mixture of particles that will restrict fracture growth. The optimized treatment design included injections of the HGC mixture prior to the main fracturing treatment. This injection was done with a nonviscous fluid to improve settling to create an artificial barrier. High-resolution temperature logging was used before the main treatment to calibrate and optimize the pumping schedule, and fracture geometry was measured independently with an acoustic scanning tool after the stimulation. The high clay content within the Ostracod layers creates a significant challenge for successful stimulation. The high clay content prevents successful acid fracturing and leads to severe embedment with conventional proppant fracturing designs. We introduced a new approach to stimulate this formation with an aggressive tip-screenout design incorporating a large volume of 12/20-mesh proppant to obtain greater fracture width and conductivity, resulting in a significant and sustained oil production gain. The carefully designed HGC technique was efficient in avoiding fracture breakthrough into the nearby water zone, enabling treatments of up to 450,000 lbm to be successfully contained above a 20-ft-thick shaly barrier with small horizontal stress contrast. Independent measurements proved that the fracture height was successfully contained. Wells treated with this optimized workflow produced up to 22,000 bbl of oil within first 8 months with negligible water cut, which significantly exceeded all previous stimulation results in the field. This trial campaign in vertical wells proved that the combination of aggressive, large fracture designs with the HGC method could help unlock the Ostracod's potential. The applied height growth control technique was modified with additional injections and improved by advanced modeling that only recently became available. These contributed to a significant increase of treatment volume, making the jobs placed in the Ostracod some of the world's largest utilizing HGC techniques. The experience gained in this project can be of a paramount value to any project dealing with hydraulic fracturing near water formation with insufficient or uncertain stress barriers.

Geomechanics plays an important role in stimulation design especially in complex tight reservoirs with very low matrix permeability. Robust modelling of horizontal stresses along with rock mechanical properties helps to identify the stress barriers which are crucial for optimum stimulation design and proppant allocation. A comprehensive modeling and calibration workflow showcased the value of geomechanical analysis in large stimulation project of Ostracod-Magwa, a compex shallow carbonate reservoir in the Awali onshore field, Bahrain. For the initial Geomechanical model regional average rock properties and minimum stress values from earlier frac 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 and elastic properties were used as input for the frac-design. Independent fracture geometry measurements were run to validate the model. The poro-elastic horizontal strain approach was used to model the horizontal stress magnitudes. This approach shows 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 of Magwa and Ostracod. Ostracod is more depleted compared to the Magwa reservoir with porepressure values below hydrostatic (~7 ppg). The B3 shale layer between Magwa and Ostracod reservoirs could be established as a stress barrier with 1200-1500 psi closure pressure. The closure pressure in Ostracod varies in the range of 1000-1500 psi while the range in Magwa is 1100-1600 psi. In the Magwa reservoir a gradual increase of closure pressure with depth is observed, while no such trend is apparent in the shallower Ostracod formation. Geomechanical models served as a key input of the integral frac optimization workflow that resulted in increasing the well productivity by more then double compared to previous stimulation campaigns. The poroelastic horizontal strain model to predict the horizontal stresses from cross-dipole sonic data provides higher stress variability and ultimately yields a high resolution stress profile. This model calibrated with direct closure pressure measuremtns is crucial for successful stimulation design in complex reservoirs with very low matrix permeability. Geology Overview and Problem Statement The Ostracod and Magwa formations are shallow reservoir development targets over the Awali field in the Kingdom of Bahrain. The depth of these reservoir ranges from 1400-1800 ft TVDSS and are represented by shallow marine limestones, which are composed of bioclastic, packstone/wackestone with occasional dolomites, chert, lime mudstone, and scarce pyrite. The reservoirs are represented by a triple porosity system which consists of matrix porosity, secondary natural fractures porosity and bioturbation enhanced porosities that can be associated with dissolution (micro-vugs). The Ostracod reservoir exhibits intense natural fractures towards the base whereas the upper part of the reservoir is associated with a combination of both, vugs and natural fractures. The section is heavily interbedded with numerous shale barriers which gives an average net-to-grows (NTG) ~ 35% with gross thickness ~150-200 ft. On the other hand, Magwa reservoir is represented by thicker limestones where the secondary porosity is mostly represented by bioturbated units resulting in a higher average NTG ~75% with gross thickness up to 150 ft. The reservoirs are heavily faulted, ~140 faults identified by manual seismic interpretation and more than 800 faults observed on the well log data by missing/repeating sections over total of ~2000 wells. Production from the reservoirs started from early 1960's mainly by perforation of watered/gas out wells from the lower producing horizons, followed by active drilling camping in 2011-2015 ~250 wells and minor drilling in 2016-2019. New drilled wells had a so-called "flash" production exhibits a high oil production rates followed by rapid production decline with the long low rate tail production. Long production history and active development drilling however did not provide good recovery factor for the reservoirs – after more than 55 years of development the current recovery factor is ~5%. At the same time, a recent new well drilling campaign provided only marginal economic production results, which opened the area for production enhancement opportunities. Based on historical production analysis and numerous acid stimulations performed on the field it was concluded that acid stimulations demonstrated a good immediate production response however the effect was not lasting more than 3-6 months (AlJanahi et al. 2020). And one of the key contributors to this effect on top of the natural depletion was the geological structure of target reservoirs – the reservoirs are not clean carbonates – they are heavily intercalated with shales. The effect of increased connected reservoir volume to the wellbore was not lasting for long due to possible fine migration and did not provide enough vertical connectivity and good lateral extension. Based on above observations, hydraulic fracturing was considered as an option for the production enhancement which could potentially provide good lateral and vertical reservoir connectivity with the wellbore and would not be heavily affected by time, or at least the effect of operation will last longer than observed historically. However, a hydraulic fracturing campaign was performed on the field in the period 2010-2011, despite good production results the incremental production after hydraulic fracturing was insignificant comparing with the wells without the fracturing. After analyzing observed results coupled with post fracturing evaluation it was concluded that the actual achieved hydraulic fracture geometry was not enough to outpace non fractured wells in these reservoirs. Based on numerical simulation studies it was concluded that the higher effective half-length and higher conductivity of a hydraulic fracture could provide better production results with much longer effect in time. Therefore, the question of achievable fracture geometry, its distribution laterally and vertically was pushed into the forefront.

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.