The expansion in recent years in the oil and natural gas sector has a profound implication for the continuous supply of energy in the market. There is no doubt a surge in the domestic natural gas production with tremendous opportunities as gas is used extensively for electricity generation. With the increasing energy demand, it is always a challenge to bridge the supply and demand gap. The era of sweet shallow gas is fast depleting and hence developing local sour gas production having higher concentration of hydrogen sulphide (H2S) and carbon dioxide (CO2), which are toxic and corrosive is seen as the viable solution. Currently, ADCO took up a project to study developing the sour gas reservoirs. The objective of the appraisal program was to gain valuable reservoir data including PVT samples to finalize the facilities and full field development plan including testing the reservoir in an area where seismic data indicated better quality sweet spots. The appraisal program was carried out and the major challenges to drill, test and produce the highly sour HPHT (High Pressure, High Temperature) gas were identified and mitigated. The data from the previously drilled wells penetrating the sour Arab zone was used to drill in the sweet spots identified but additional data was required to reduce the remaining key uncertainties to firm up the Gas In place volumes as the final results were crucial for strategical decisions. This paper highlights the work progress and then the lessons learned during each step of the operation with the proposed mitigation to safely and efficiently drill the appraisal wells in the Arab sour reservoir having 37% H2S and 10 % CO2.
Drilling extended reach drilling (ERD) wells starting from the planning phase and engaging various disciplines including drilling, cementing, drilling fluids and geoscience teams. The pre-well engagement and integration between multiple disciplines are vital to define the associated drilling/geosteering challenges and accordingly optimize the drilling program to deliver a successful ERD well. These challenges are included and not limited to geological model uncertainties, differential sticking, high torque and drag, ECD limitation, friction factors and expected mud losses. An integrated and optimized plan was constructed to meet the associated challenges. The drilling engineering team optimized the bottom hole assembly (BHA) design in all sections to ensure a smooth profile using optimum drill bits designs. The BHA included LWD technologies to mitigate the geological challenges and helping in determining the casing points and geosteering operations. A new generation of intelligent fully rotating high dogleg pushthe-bit rotary steerable system was selected with matched drilling bits to geosteer the well in the thin target layer while maintaining the planned target trajectory with minimum borehole tortuosity by means of realtime drilling optimization. Effective collaboration led to successful delivery of the first extended reach well, the geosteering objectives were achieved with 100% reservoir contact and delivered 20,000 feet targeting thin carbonate layer and overcoming the complex geology environment. The well was drilled to record depth of 32,300 feet with 29% ROP improvement in same field. ECD was always maintained below the fracture gradient along with optimal hole cleaning without cuttings buildup or tight hole while reducing the wellbore friction to ensure smooth pulling out of hole operation. Cementing operations were successfully achieved and ensured zonal isolation. Furthermore, a customized and innovative drilling fluid with free RDF Non Aqueous Fluid (NAF) and compatible lubricant were deployed along the different hole sections to reduce the expected induced losses and provide proper hole cleaning. The cementing program has been optimized for the 18 5/8", 13 3/8" and 9 5/8" casings using an innovative flexible expandable lead and tail slurries with enhanced mechanical properties to mitigate the expected losses while cementing and ensure proper isolation across all formations. The best practice of the multidisciplinary approach along with the captured lessons learned opens the door to drill more challenging wells. in addition, it proved that proper planning and execution can shift the boundaries further and gave confidence to drill even deeper.
The Operator planned and conducted Underbalanced Coiled Tubing Drilling (UBCTD), operations on 3 wells in Operator Onshore fields targeting tight sour gas carbonate reservoirs. The objectives of these operations were to evaluate the applicability of the technology in these fields, to understand requirements and methods of the technology and to evaluate the benefits of drilling the target formations in an underbalanced mode. As a preliminary step, the Operator conducted a feasibility study that flagged potential limitations to deploying UBCTD operations in existing wells, due to limitations on the completion design and other factors. All of this resulted in the plan to drill fit-for-purpose wells to the top of the reservoir to facilitate the deployment of the technique. These wells were completed with 5.5/4.5 in. Tubing and 7 in. Liner and left with a 100ft open hole interval from where CT drilling operations would later continue. The results of the feasibility study notwithstanding, additional detailed engineering work was performed in all aspects of the design by the operations team to ensure the success of the trial, including a review and validation of the available data and the feasibility to deliver the stated objectives (lateral length, underbalanced conditions, minimal flaring operations, drilling fluid re-circulation, etc.). As a result of this approach, all three wells were successfully drilled in underbalanced conditions and to the target lateral length of 4,000 ft. Well placement was facilitated using Biosteering techniques and continuous monitoring of the well performance vs. drilled footage, allowing steering decisions to be made in real-time to maximize the production of each lateral, resulting in outstanding production results of 3x the productivity of similar wells drilled conventionally, (after stimulation). This paper will detail the design process highlighting key engineering decisions and assumptions taken during the design process and comparing them to the actual behavior of the well and the impact of real-life constraints on the operational parameters. The base design and lessons learned from the project will serve as a launching pad for planning and efficiency gains for future UBCTD operations.
Objectives/Scope The development of Abu Dhabi's sour gas is not without its challenges. Deep drilling in some fields presents its own set of difficulties due to high temp and pressures coupled with +30% H2S and +10% CO2. Handling of these corrosive reservoir fluids both while drilling and then testing, requires deploying advanced technology to meet the specific requirements of these reservoirs, along with the infrastructure necessary to handle the toxic and corrosive products while testing in a brown field safely. Methods, Procedures, Process Developing local sour gas production is seen as the answer to resolve the ever growing energy needs for UAE but the technical requirements for the project is stretching the limits of the industry. Results, Observations, Conclusions What did we do different: Developed and implemented specific HSE procedures and SIMOPS due to close proximity with major populated facilities which could not be shut-down during the testing period. Conducted multiple audits and drills with the local authorities including Civil Defense and local Police. Additional 3rd part supervision was provided to ensure all personal are complying with the policy and procedures developed. Installed 2 green burners and 2 vertical 90 ft flare stacks at 180 degrees. This was to cater for the changing wind directions for continuous operations and as back ups. CCTV monitoring for green burners / flare stacks was conducted although this was a rigless operation 3 circles of H2S detectors and sensors were placed around the testing area and the flare stakes and green burners to detect any H2S gas. (Covering all 360° directions). Blowdown/Depressurization valve was installed at separator, storage tanks apart from Automatic and manual shutdown system upon H2S detection Installed Optic Fiber cable from wellhead to the main control room for monitoring purposes All piping connections used were flange-to-flange as welded joints could have caused stress cracking on the weak points For Sour well operation, used fully cladded X-mass tree & Inconel well completion Considered setting of compatible TTBP (Thru Tubing Bridge Plug) for staked reservoirs zonal isolation Instead of coil tubing cement plug for accurate depth calculations. Arranged Special chemical for any scale cleanout for handling of elemental Sulphur. Arab zones were stimulated with specialized acid recipe developed exclusively for this temperature, pressure and sour conditions downhole. Bottom hole measurements were recorded successfully and all the necessary data was acquired. Novel/Additive Information This paper highlights the major challenges identified and mitigated to test and produce the highly sour HPHT gas during the appraisal program complying with ADNOC 100% HSE in a brown field without disturbing the other major operations being performed in the vicinity.
The nature of tight gas reservoir consists of heterogeneous sub-units separated by impermeable denses and various depletion level has become the greatest challenge on how to exploit this typical reservoir at its maximum. Despite maximum reservoir contact is the best method to deliver the highest well production, this paper tries to tell another success story about UBCTD applied in a triple lateral well which can deliver greater productivity than a normal overbalanced multilateral well. The study methodology begins with the evaluation of the current remaining potential sweetspots throughout the reservoir. The assisted history matching is used to generate 3 different model realizations: Low - Mid - High case that can map-out sweetspot distribution called Simulation Opportunity Index (SOI) map. SOI integrates 3 independent components selected from static and dynamic parameters: reservoir permeability-thickness, movable gas and reservoir pressure from a historically-matched dynamic model. One particular area is then selected and evaluated furthermore for the final new well and trajectory placement. The well was drilled as a triple lateral with one of the lateral was fully placed in prime sub-unit that likely holds the potential remaining sweetspot in the area according to SOI method with expectation to maximize its recovery. During the drilling, UBCTD technique was implemented because it offers several advantages such as reduction of formation damage, reduction of drilling fluid loss into formation, avoiding losses-related drilling problems and risk of differential sticking and creating cost saving for completion and stimulation requirements. Earlier study in the field signified that generally, the well productivity is strongly influenced by the type of the lateral and the geological structure. For instance, the triple lateral well located at higher structure normally gives higher productivity than the triple lateral well located underneath it. Theoretically, higher productivity will be given by the triple lateral compared to the situation if the same area is developed by dual lateral or even by the single lateral well. Currently, the implementation of UBCTD in this triple lateral well was confirmed to provide better productivity up to double exceeding a conventional overbalanced with the same well laterals. Greater initial gas production rate with high THP was evidenced during the well clean-up. UBCTD application in tight gas reservoirs is not only aimed to improve the initial well productivity significantly beyond the conventional overbalanced well but it is also expected to create more equal pressure drawdown distribution along the lateral drain because of many given advantages as stated above. At last, cost saving can be performed because the operating cost which is usually spent on normal wells for well stimulation can be reduced.
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