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Achieving successful stimulation with optimum production performance in open hole horizontal completions is complex in carbonate reservoirs. When stimulation becomes necessary in openhole completions, methods to perform multistage fracturing with proper isolation, are limited. Effective application of dynamic diversion provides a fit for purpose solution to this challenge, allowing to selectively place fracturing treatments, reaching the productivity enhancement targets. Prior to applying this technique a series of formation testing needs were conducted, including step rate test and leak off test. Outputs of the tests help optimize pumping schedule and strength of the acid mixture. The method involves dynamic isolation while performing dual injection of acid through Coiled Tubing (CT) and water-based fluid through annulus. A precise fracture initiation is established through the stagnation pressure developed when the CT fluid is jetted at high velocity. The pressure generated act as barrier replacing mechanical isolation (Surjaatmadja 1998, Surjaatmadja et al. 1998). Dynamic diversion is achieved with a specially designed downhole Hydrajetting tool, which generates a specific pressure drop across its nozzles. Down-hole acid mixing is highly influenced by leak off rate along the open-hole section, as well as the maximum allowable rates through CT and Annulus; this is particularly critical for surface preparation of the fracturing acid. Treatment acid is pumped through the CT at highest possible pumping rate within the pressure limitation of the CT. Fresh water based fluid is pumped in the annulus at 80% of the fracture gradient. Reservoir stimulation with this technique allowed completing 20 treatments in less than 18 hours, proving its remarkably efficiency. With proper depth correlation, the project targeted the sweet spots as initially designed based on petro-physical and geomechanical properties of the reservoir along with the presence of natural fractures network. Post-treatment rates observed during the initial production suggested the method is effective for acid fracturing of carbonate reservoirs with gas-condensate. Post-fracture simulations involving treating pressures matching and initial production analysis, support these observations. Recommendations are focused on technologies to perform additional measurements confirming fractures geometry achieved and contribution to production. Beyond isolation, the petrophysics and geomechanics of the zone of interest as well as the surrounding formations represented additional challenges. Leak off along the horizontal and depleted adjacent layers required an accurately engineered pump schedule. Several combinations of rates, volumes and fluid types had to be simulated to obtain the optimum design. The paper summarizes the design processes, selection criteria, challenges, and lessons learned during the planning & execution phases. It will also pave the way for future development of tight carbonate reservoirs which are available in company's portfolio currently undeveloped due to insignificant well productivity with important in place volume.

Although hydraulic fracturing is widely employed throughout most of the Middle East Region's carbonate reservoirs, it remains a relatively unused improved oil recovery (IOR) technique within the Emirate. Given the Company's goal to increase gas production, an in-country initiative was mandated to progress hydraulic fracturing of low permeability reservoirs. A multi-disciplinary project team was created and tasked to prove that hydraulic fracturing of a single horizontal lateral would give an improvement in well performance and value to that of the current technique of drilling open hole tri-laterals. The first step of the project to develop fracturing capability and best practices, required detailed up front planning by drilling a vertical pilot hole to collect data to build the mechanical earth model (MEM) and thus improve the fracture modeling and design. The challenges faced in the project so far were: Data sourcing, calibration and modelling. Low permeability sour gas reservoir with H2S and CO2 around 7%. Gross reservoir thickness less than 50ft. and the absence of strong mechanical barriers to adjacent depleted reservoirs. Limited experience of hydraulic fracturing and conducting operations with a drilling rig. Zonal isolation for open hole multi-zone hydraulic fracturing in low permeability reservoirs. Technical and commercial processes for sourcing required equipment and optimising job execution. This paper will outline the strategies and tactics employed to implement fracturing in low permeability, thin, sour gas reservoirs, as well as the technical, operational, logistical and contractual challenges that have had to be overcome to date. The stated challenges and also that of operating under current restrictions due to global virus conditions will be described. The contents of the paper and subsequent material will build a Best Practice to successfully implement hydraulic fracturing operations in the Emirate.

Hydraulic fracturing is the industry-proven technology for efficient exploitation of tight reservoirs. This study evaluated the technology by drilling horizontal wells through acid fracturing the low permeability gas reservoirs of a lower cretaceous carbonate formation, located onshore Abu Dhabi. 1D Geomechanical modeling was critical in determining fracturing strategy. Containment of fracture height growth was the most critical aspect of the fracturing process, as the target units were stacked within heavily depleted reservoirs. The challenge was that the rock strength, poroelastic behavior and stress paths vary significantly through the various formations overlying/underlying to target reservoirs. In addition, the depositional nature of the target reservoirs meant inherent variations in rock mechanical properties. Hence, a continuous profile of in-situ stresses and other rock mechanical properties was essentially mandatory for addressing the challenges for optimal placement of the horizontal drain hole and assessing fracture height growth. Existing rock mechanical measurements, dipole sonic and image logs, as well as in-situ stress measurements were reviewed for 400ft (TVD) interval above and below the target reservoirs. Significant data gathering was managed in the vertical pilot hole of the first well to fill data gaps. A custom-built workflow was performed for 1D Geomechanical modeling in the first well, integrating poroelastic modelling with failure models. The study integrated drilling-induced and production-induced Geomechanical aspects into the 1D stress profile, including depletion-induced poroelasticity, shear anisotropy, and rock mechanical heterogeneity. Wellbore failures observed in vertical pilot hole and the in-situ stress measurements from offset wells were used for validating 1D Geomechanical model. This work resulted in a rigorous 1D-stress profile that contributed to initial fracture modelling, whilst de-risking the fracture height growth into the depleted reservoirs and optimizing the choice of drain hole location within sub-units of the target reservoirs. The fracture gradient and breakdown pressures derived from 1D stress profile were found to be in very close agreement with that measured from the minifrac conducted in vertical pilot hole of the first well. This paper presents a purpose-driven workflow designed specifically for these circumstances. The merit of the workflow lies in its systematic and methodical approach, providing solutions to various Geomechanical problems relevant to the target reservoirs, as well as the depleted reservoirs above and below. The results are beneficial for analogous fields where hydraulic fracturing is required to improve recovery of low permeability reservoirs in mature fields

Planning complex well designs for multilateral and extended reach wells presents substantial challenges for optimizing well construction, drilling risks, and economics. The subject well of this case study is located in a prolific onshore field in Abu Dhabi; the field has been producing for many years, giving rise to pore pressure uncertainties between different reservoir sublayers. The primary challenges are associated with reducing drilling time for the future development program while delivering optimized drilling performance and cost effective openhole side tracks with rotary steerable system (RSS) bottomhole assemblies (BHA), eliminating extra trips, and enabling accurate formation evaluation and precise well placement. Goals included optimizing drilling parameters in accordance with rig capabilities, addressing anti-collision concerns, optimizing mud weights to mitigate differential sticking, maximizing reservoir exposure in thin reservoir sublayers, and minimizing the surface footprint. Close collaboration between the operator and the directional drilling/logging-while-drilling (LWD)/geosteering service provider was a key component of developing a fit-for-purpose solution. This solution consists of a comprehensive feasibility study using historical field data, a detailed pre-planning process that includes well and BHA design; anti-collision; and optimizing sidetrack points, LWD configuration, and tool downloads for longevity. The well plan incorporated a trilateral design with optimized trajectories for minimizing dogleg severity (DLS) and borehole tortuosity in the horizontal laterals while cutting the poor porosity layers that separate the targeted four thin reservoir sublayers. The mother bore trajectory also included humps (building the inclination from 89° to 91°, then returning to 89° within 50 ft with 4° DLS) to facilitate openhole sidetracks without the need to pull out of the hole (POOH). The BHA included a RSS with azimuthal density, neutron porosity, gamma ray, and propagation resistivity tools. The alternative BHA included azimuthal deep resistivity and acoustic LWD sensors to meet complex drilling, geosteering, and petrophysical data gathering requirements. A formation tester while-drilling sensor was also included to provide accurate pore pressure measurements to optimize mud weight in real time. Continuous (24/7) real-time operation support provided drilling performance monitoring and analysis, and facilitated geosteering services. Three horizontal laterals of 5,000 ft each were successfully drilled with openhole sidetracks without POOH for the first time in the United Arab Emirates. Mud weights were optimized by reductions from 78 to 70 pcf, and 100% reservoir exposure was attained in all three laterals. Finally, significant improvement in production and cost savings, as compared to traditional single lateral designs, prompted a review of the future development drilling program. This paper presents a step change from traditional field development drilling techniques in terms of well construction. Similar well designs are currently being implemented to benchmark drilling, well placement, and petrophysical data gathering requirements for future development drilling to maximize asset value.

ADNOC onshore tested HPHT sour gas reservoirs with 30% H2S, 10% CO2 to evaluate the reservoir and well potential as part of the efforts in supplying additional gas for meeting country's growing energy needs. Developing these massive HPHT sour gas reservoirs is essential for providing a sustainable source of energy for years to come. This critical project serves the broader national strategy and country aspirations in fulfilling the gas demand over the next few decades to come. Few HPHT sour wells were drilled but only one well could be tested successfully. The other two wells had to be suspended due to HSE /environmental and operational reason as elemental Sulphur was detected. Based on the previous well test and reservoir data, it was decided to use one of the existing well and sidetrack in the Sour reservoir to gain experience about drilling a long horizontal section in the High pressure, high temperature sour condition. A specialized drilling Rig capable of drilling the long horizontal well was selected. Due to nature of the reservoir, specialized sour service drilling tools were selected considered the long departure and long open hole horizontal length of 10000+ ft. Selection of the downhole material for these conditions was itself a challenge as very few vendors or IOC (Internatioanl oil companies) have experience of developing and producing from +30% H2S and +10% CO2. Due to the location of the well, stringent HSE measurements were adapter to ensure zero tolerance for the safety violation in accordance with 100% HSE. The testing of the HPHT sour gas was challenging due to not only HSE issues but also from the environment part too as flaring needed to be minimized in the brown field. Hence, it was decided to Tie-in the well to the nearby facilities. The challenge was that the existing facilities were not design to accept the sour gas. This was overcome by blending the sour gas with sweet gas to meet the existing facilities specs and capacities. After the well was drilled, the +10000 ft. open hole was flowed to clean to ensure all the drilling fluid lost was recovered to test to access well potential and obtain representative data for full field development plan. Drilling, testing and producing the highly sour HPHT gas reservoirs with more than 30% H2S and 10% CO2 along with temperature ranging up to 300 deg F is itself a huge challenge. Over the last few years, ADNOC Onshore have developed considerable expertise in testing the sour wells considering all the safety and environmental aspects. This paper highlights the work progress and the lessons learned during each step of the operation from planning phase to drilling, tie-in the well to the existing facilities after dilution during testing. All the proposed mitigation plans considering 100% HSE while dealing with these appraisal wells in the Arab sour reservoir having +30% H2S and 10 % CO2 were developed and implemented sucessfully.

Recently multilaterals wells are drilled in selective reservoirs in ADNOC Onshore fields for development of hydrocarbon gas in Abu Dhabi. The targets are commonly thin multilayered carbonate reservoirs. The development strategy of multilaterals has significantly enhanced the reservoir contact aiding higher drainage. Multilateral wells can significantly reduce well counts while still achieving robust recoveries. Benefits of using multilaterals included the acceleration of gas production and the reduction in CAPEX/OPEX . The reservoirs are targeted by drilling duel and triple lateral holes. In triple lateral wells, a main horizontal borehole is drilled followed by laterals on either side of the main borehole. There are challenges of drilling multilaterals as the multilayered reservoir subunits are thin and selective drainage is planned in each sub layers in 6" horizontal sections. It is imperative to have a detail well planning with industry standard drilling technology to deliver successful multilaterals. During the well planning stage the laterals are planned in 60-80deg azimuthally apart from main both, on either side. The laterals drilled by performing open-hole sidetrack from the main bore, which apparently has a challenge of success. During initial stage of the campaign, lessons learnt from applied practices has encouraged an innovative way for successful multilateral drilling. Wells are landed on top of the target reservoir. 6" horizontal main bore hole is drilled with creating three humps in the initial part of the well trajectory. The humps are high inclination short section of well path with high Dog Leg Severity. These humps are strategically created at selected points with 300- 500 ft gap from each other and are used to kick off open-hole sidetrack of the lateral holes. Recorded real time inclination (RTI), Image log data and porosity of main bore along the humps are the key factors considered before executing the side track. MWD-LWD triple combo along with image log are used in the main bore and tools without radioactive source are used while drilling lateral holes to offset the risk of stuck-up of BHA carrying radioactive source tool. A detailed step wise operational procedure has been identified and introduced for the success of this development strategy. The high-confidence, successful open hole sidetracking strategy has aided maximum reservoir contact in 6" section with minimum risk and rig time and has substantially contributed to offset additional cost and rig time in all the multilateral wells in ongoing gas development drilling. This multilateral drilling and field development strategy has been a combined effort of geoscience and directional drilling and have paved way for successful open hole sidetrack campaign with proven standard procedures.

This case study is of drilling extended reach 6" lateral (more than 7,000 ft) in thin multi -layered carbonate gas reservoirs with a novel approach of tapping the multiple target reservoir units in dual points starting from top reservoir unit to the base unit and placing the well back to top reservoir unit in steps. The well trajectory was planned with Top-Bottom-Top (TBT) approach, starting from top to bottom layers and steering back to the top layer in stair-step trajectory. The MWD-LWD BHA was selected to continuously monitor the porosity to avoid exiting from porous subunits – owing to the thinness of sweet spot in reservoir subunits with the range of 4 to 5 ft. only. Azimuthal Resistivity tool with LWD triple combo was used while geosteering the well to assess and map the subunit boundary as there is good resistivity contrast between porous subunits and bounding stylolite. LWD Pressure Formation Tester was used to record the current reservoir pressure in the target reservoir for the purpose of optimization of the mud weight to avoid the risk of differential sticking due to higher overbalance. The differential sticking was experienced in the previous wells due to higher mud weight and overbalance. Hence, mud weight optimization helped to drill more than 7000 ft of 6" horizontal section with a complex stair-step well trajectory design. The first 5,000 ft of horizontal section have been drilled successfully using distance to boundary Azimuthal resistivity tool in addition to density-neutron tool. While in the remaining of 2,000 ft horizontal length of drain hole, the radioactive source tool was replaced with source less BHA of azimuthal resistivity and sonic tools. The reason for replacing source tool with sourceless tool is the risk of string stuck up with radioactive source in the BHA. This may be caused by complex stair-step well trajectory, reservoir pressure uncertainty and any down hole complication. The target reservoir identified for this approach has low average permeability of less than 1 mD with limited sweep area. The target is thin stacked reservoir subunits of thickness ranging from 4 to 8ft. The Subunits porosity range is 3 to 17% and are distinctly bounded by thin non-porous stylolite. The risk of drilling with complex well trajectory was handled by constant maintenance of dogleg severity (DLS) less than 2deg/100ft. Each subunit was targeted with very gentle inclination and inter-bedded stylolites were cut with higher inclination to achieve more than 90% of reservoir contact. The project has resulted in reservoir characterization in selective areas with selective drain. Being laterally heterogeneous, the Top-bottom-top approach provides the scope of selective drain in the reservoir along the well path. A higher production performance is expected from this approach as each subunit was targeted according to their reservoir properties. This case study proves to be novel especially in tight reservoirs with limited drainage area, where cost have been optimized by reducing the number of wells to be drilled by tapping the reservoirs in dual drainage points with a single well.

Decades of field development in onshore Abu Dhabi fields has resulted in significant operational challenges in planning and drilling new wells. These highly congested fields pose a high risk of well collision due to inherent range errors in the accuracy of well survey measurements obtained during the life of individual fields and reservoirs. The study discusses a methodology for improving and normalizing the accuracy of legacy wellbore survey data to aid successful planning of recent multilateral drain hole strategy and how real time data corrections can aid in accurate wellbore placement. Multilateral wells are risked by higher collision issues for having target areas in separate azimuths from single surface location (SL). Proposed wells were subjected to lower Separation Factor (SF) due to high density of wells. In the study area, survey data of existing vertical and horizontal wells in upper and lower reservoirs in the proposed well path were studies and plotted in well sections and maps in Geological model. Well anti-collision runs of proposed lateral holes with offset wells were done in drilling planning softwares. A notional model study carried out with one of the proposed triple lateral wells in ADNOC Onshore with nearest offset wells with MSA and SAG correction resulted in collision risks being reduced by 52% and hence qualifying with the minimum SF required for safe drilling. Recent reservoir development strategy in an Abu Dhabi Onshore field is to drill trilateral wells targeting multilayered reservoirs to maximize production while optimizing sweeping efficiency. Well survey quality management with In-Field Referencing (IFR), Multi Station Analysis (MSA) and SAG Correction are the primary steps to be applied to MWD survey measurements to reduce the well collision risk. The normal well anti-collision study with nearest offset wells is mandatory as per standard drilling practices and with densely populated wells in one of the giant Abu Dhabi Onshore fields, it is becoming challenging to meet the minimum separation factor (SF>2) required by the company policy. A survey correction in all legacy wells followed by real time survey correction in triple lateral wells will add a significant value concerning collision issue in the proposed triple lateral campaign. With growing number of wells in highly congested fields, Pad drilling coupled with advance survey management technique will result in high value addition for future drilling campaigns without having collision risks and hence pave the way for future infill development strategy without subsurface space constraint.

During normal rig workover operations, once the old completion is retrieved, corrosion log is being executed to check the condition of the casing and/or liner as one of the means to establish a way forward. Decision can be made easily in case of pipe found completely corroded or absolutely intact. However, such clear scenarios are not always the case and the decision making takes significant time, specially if corrosion log results are received at night time or during the week end. It may become a subject of hot discussion between involved stakeholders, trying to find a right balance between safety and operations. Therefore Gas Development Operations Subsurface Team of ADNOC Onshore requested Technical Center Well Integrity Team to identify clear criteria in advance, to save rig time and improve business performance and decision making process. Based on this request Technical Center developed a strategy of predefined well integrity criteria's that are being successfully used now, saving rig time during workover and avoiding conflicts between teams in questionable situations. The method is based on several factors: Maximum Allowable Annulus Surface Pressure (MAASP) calculation as per Norsok D10 standard, application of Double Barrier concept for Secondary Well Barrier Envelope, sensitivity analysis based on MAASP degradation and remained wall thickness of casing and/or liner. This method has already been successfully implemented in several wells during workover operations saving time for decision making. It is planned to be included in the next release of corporate procedures. Method, explained in this paper can be used as a guideline by all petroleum engineers, drilling engineers, well integrity engineers and petrophysicists who are involved in workover operations, helping them to improve decision making process based on the results of the casing corrosion logs. In addition, the subject of well life prediction and well life extension in standard Company well design is covered, with focus on safety during workover operations.

Development plans in largely depleted carbonate gas bearing reservoirs are dependent upon having a complete understanding of reservoir mechanical behavior under change of in-situ stress state. The accuracy of 3D geomechanical models relies highly upon proper tectonic strain and stress calibration using in situ straddle packer microfrac testing conducted in vertical pilot wellbores. Pipe-conveyed straddle packer microfrac tests have become an important technology to measure in-situ fracture closure stress in depleted and non-depleted reservoir layers in order to quantify the stress contrast among multiple intervals with different reservoir pressure regimes. This case study describes the use of microfrac tests to validate and calibrate the horizontal stress profile in various reservoir intervals of a carbonate formation that had been developed to a substantially depleted condition. Well-injection plans, cap-rock integrity assessment, stress contrast, hydraulic fracture containment, and minimum horizontal stress estimations can all be quantified from multiple microfrac tests recorded at various depths of the reservoir formation. The fracture closure analysis was conducted using three different methods: (i) square-root of time, (ii) G-function and (iii) Log-Log plot. The final fracture closure measurement was obtained after consolidating the three fracture closure identification methods in all injecting cycles conducted on each microfrac station. The integrated post job microfrac analysis includes borehole acoustic processing and resistivity imaging. The borehole acoustic response is used to estimate not only formation mechanical properties but also log-derived stress profiles while borehole Imaging is used to select the microfrac points and to confirm the induced borehole fracture created during the pressurization of the straddle packer tool. Formation breakdown, fracture reopening, propagation and closure at multiple reservoir layers provide the necessary in situ measurements to calibrate the stresses change due to pore pressure depletion. This information provides a better understanding of the in situ stress state in depleted formations that reduce risk in designing future gas development strategies in the field.

This paper examines the relationship between corporate governance ratings and firm performance using two commercial governance ratings- the Globe and Mail Report on Business (ROB) rating and the Institutional Shareholder Services (ISS) Governance Quickscore. Firm performance is measured as Return on Assets (ROA), Return on Equity (ROE), Tobin’s Q and Market – to – Book (MB) ratio. For the ROB ratings, a panel data of 119 firms in the three-year period 2010-2012 was analyzed using univariate and multivariate analysis. The ISS rating for the same firms was examined using Ordinary Least Squares (OLS). The univariate analyses show differences in performance change between good governance and poor governance firms for Tobin’s Q and MB ratio. There is also evidence of a difference in MB ratio between high governance risk and low governance risk firms for the ISS rating. The multivariate analyses show significant positive relationship between the sub categories of ROB ratings and firm performance measures; there is however no evidence for the overall score. For the ISS rating, there is evidence that high governance risk firms perform lower than low governance risk firms. Also, there is evidence of some significant relationship between the sub-category scores and firm performance. This study contributes to literature by using a new data source of governance ratings for Canadian firms – ISS and provides more evidence that the sub-category ratings reflect firm performance better than the overall scoring. The results of this study are important to investors, companies and policy makers.