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This field produces from a structure that lies above a deep-seated salt dome (salt has been penetrated at 9,000 ft) and has moderate fault density. A large north/south trending fault divides the field into east and west areas. There is hydraulic communication across the fault. Sands were deposited in aeolian, fluvial, and deltaic environments made up primarily of a meandering, distributary flood plain. Reservoirs are moderate to well sorted; grains are fine to very fine with some interbedded shales. There are 21 mapped producing zones separated by shales within the field but in pressure communication outside the productive limits of the field. The original oil column was 400 ft thick and had an associated gas cap one-third the size of the original oil column. Porosity averages 30%, and permeability varies from 10 to 1500 md.
Most drilling problems result from unseen forces in the subsurface. But the equipment involved can also be a source of problems, as can personnel. The integrity of drilling equipment and its maintenance are major factors in minimizing drilling problems. Given equal conditions during drilling/completion operations, personnel are the key to the success or failure of those operations. Overall well costs as a result of any drilling/completion problem can be extremely high; continuing education and training for personnel directly or indirectly involved is essential to successful drilling/completion practices.
Abstract For several decades, completion design has been performed by the Field Development (FD) Team of several offshore fields in Abu Dhabi and installed with minimal Completion Engineering Team contribution. The demand of lower completion requirement has being increased to maximize well portfolio and enhance well life. The completion design is becoming more challenging and import for key to success. Since a companywide re-organisation occurred a dedicated Completion Engineering Department has been formed to develop a plan to standardise & optimise completions in order to reduce phase duration and NPT. A plan was approved that involved the hiring of a complete engineering department with expertise in many different types of completion and workover operations from all over the globe. This engineering team was brought together from other oil companies and service providers, and tasked with reviewing all current and future completion designs, operations procedures and completion equipment. This was done in order to identify suitability and gaps that were the cause of well construction NPT and identify processes that could be used to reduce or eliminate possible future Well Integrity problems. When the new organisation was formed completion phase NPT reached over 20%, however three month after the NPT had dropped to 11.1%. Within six months of the engineering team starting to be formed, completion phase duration has reduced by 20% and NPT has reduced by almost 50%. These results have been achieved with a concerted effort to maximize understanding of the equipment available to be deployed and develop standardized completion designs that meet the functional requirements of the Field Development Department. As the department has grown and moves forward, a greater involvement in the development of documents such as but not limited to: scope of work and technical requirements for procurement; further deepens the engineering-centric approach that will continue reducing completion phase duration contributing to the operator strategic goals. This paper will show how the newly formed engineering team has managed a complex change from a previous organisation to a new one. Whilst the previous completion design and execution methodology was seen to be successful in other operating companies, the successful engineering-centric approach has been proven within other national operator offshore concessions to reduce phase duration and NPT.
Nafikova, Svetlana (Schlumberger) | Ramazanova, Yulia (Schlumberger) | Muslimov, Alexander (Schlumberger) | Akhmetzianov, Ilshat (Schlumberger) | Jain, Bipin (Schlumberger) | Kim, Alexander (Lukoil) | Zvyagin, Vasily (Lukoil)
Abstract Achieving zonal isolation for the lifetime of oil and gas wells is crucial for well integrity. Poor zonal isolation can detrimentally affect well economics and increase safety-related risks because of pressure buildup with unpredictable consequences. Additional local regulations prohibiting production of a well with positive pressure in the annulus made sustained casing pressure a major challenge for operators in the North Caspian Sea. An innovative cost-effective solution was required to resolve this challenge. Historical well analysis proved that previously applied cementing approaches were ineffective. Several modifications were required to define the effective solution. Implemented changes included revision of the casing setting depth, optimization of the drilling fluids and spacer formulations, and implementation of the self-healing expanding cement. Carefully engineered placement of the self-healing cement system was the key to success. If cracks or microannuli occur and hydrocarbons reach the cement and flow through the cracks, the system has the capability to repair itself, thus restoring integrity of the cement sheath without external intervention. This technology has been used in 11 extended reach wells in two fields with excellent results. The collaborative approach with drilling engineers eliminated the challenging sustained casing pressure issue in two major offshore fields in North Caspian Sea. In addition to the existing cementing best practices available in industry for mud removal efficiency enhancement and successful cement placement, the newly implemented methodology included potential requirements for well trajectory adjustments, implementation of the real-time control during cementing job execution, engineered placement and optimization of the self-healing expanding cement system formulation, and a specifically developed "initially required" bleedoff schedule that allows acceleration of the self-remediation cement capability. The self-healing cement was designed with low Young's modulus for maximum flexibility. Expanding additives were also incorporated into the design to minimize the risk of set cement integrity failure due to microdebonding from bulk shrinkage after setting. Adherence to the mutually developed flowchart for the drilling and cementing stages improved the zonal isolation of the critical hydrocarbon zones in the extended reach wells and increased the success ratio of the wells with no pressure buildup from 30% to almost 100% within the last 5 years. As a result, the self-healing cement technology and developed approach, which is discussed in this paper, have become the standard for both fields for all future wells. The complex engineering approach described in this paper expands the existing best practices in the industry for zonal isolation improvement of the extended reach wells and provides a new effective solution for eliminating sustained casing pressure problems. The design strategy, execution, evaluation, and results for two sample wells are discussed in detail to help to guide future engineering and operational activities around the world.
Matt Mantell wasn't always sure that completing horizontal wells with wet sand was going to be as efficient as using smooth-flowing dry sand. But after proving how well it does work, and how much money it saves, the completions engineering advisor with Chesapeake Energy said the plan to use wet sand at every possible opportunity is moving "full-speed ahead." Wet sand represents a new trend in the US shale sector that has spread from operator to operator. After the sand is washed free of unwanted particulates at the mine, it has historically been dried before being delivered to a wellsite. Wet sand is instead loaded straight from decanting piles.
M Yusof, M Hatta (PETRONAS Carigali Sdn Bhd) | Sulaiman, M Zarkashi (PETRONAS Carigali Sdn Bhd) | A Bakar, M Faiz (PETRONAS Carigali Sdn Bhd) | Alwi, M Fairuz (PETRONAS Carigali Sdn Bhd) | Muslim, Fadli Adlan (PETRONAS Carigali Sdn Bhd) | Fabian, Oka (PETRONAS Carigali Sdn Bhd) | Bela, Sunanda Magna (PETRONAS Carigali Sdn Bhd) | A Ghani, Syazwan (PETRONAS Carigali Sdn Bhd)
Abstract This paper describes a step change by well completion group in adopting Single Trip Liner Open Hole Completion (STRIP-LOC) technology, basis of selection, design, and operation approach. This has contributed to the reduction in initial well cost estimates thus benefited overall project cost. The technology adoption signifies the importance for continuous design improvement, operational optimization, and capital expenditure reduction, while not compromising with technical and HSE standards.
Mhd Yusof, Muhammad Hatta (PETRONAS Carigali Sdn Bhd) | Khalid, M Zulfarid (PETRONAS Carigali Sdn Bhd) | A. Halim, Rahimah (PETRONAS Carigali Sdn Bhd) | Ahmad Fauzi, Nurfaridah (PETRONAS Carigali Sdn Bhd) | Sella Thurai, Ahgheelan (PETRONAS Carigali Sdn Bhd) | Omar, Ahmad Faiz (PETRONAS Carigali Sdn Bhd) | Alwi, M Fairuz (PETRONAS Carigali Sdn Bhd) | Sulaiman, M Zarkashi (PETRONAS Carigali Sdn Bhd) | Muslim, Fadhli Adlan (PETRONAS Carigali Sdn Bhd) | Fabian, Oka (PETRONAS Carigali Sdn Bhd) | A. Bakar, Mohd Faiz (PETRONAS Carigali Sdn Bhd) | Lee, Magdelene Jia (PETRONAS Carigali Sdn Bhd)
Abstract This paper will discuss the case study of two (2) projects in Malaysia that were stretched-to-limit and optimized ‘on-paper’ all the wells’ related engineering design and construction, operation activities pre and during drilling campaign as well as logistic arrangement, which led to significant cost reduction in wells and thus improving the overall project economics. This significant savings achieved with full compliance to technical standards as well as with the betterment to improve HSE during offshore execution.
Abstract A large collection of data recorded during coiled tubing (CT) operations has been analyzed using proprietary pattern recognition algorithms to identify downhole events with a high degree of confidence. These events include the drilling of plugs and stuck pipe incidents. Key performance indicator (KPI) metrics derived from this analysis provide insight into industry trends over time and by region, and can provide useful performance benchmarks for service providers and operator companies. Depth, weight and pressure data from multiple sources has been streamed and stored on a shared platform over a five year period, creating a record of over 39,000 data files. This data was processed to generate KPI-type statistics for over 500,000 detected plugs and 760 possible stuck pipe scenarios, based on analysis of depth and weight signatures. Using surface measurements to quantify downhole events has some limitations, but the method has proven sufficiently robust to allow useful trends to be observed and evaluated. While the analysis is confidential to the parties involved, a contributing company can compare their ‘performance’ statistics (as evaluated by the third party algorithms) against averages representative of the industry at large, arranged by year and geographic region, to identify areas of relative strength or weakness. An operator company can likewise compare metrics for different service providers (derived solely from jobs performed for their company) for those which elect to share data in this fashion. This paper presents statistics for plug drilling operations and stuck pipe incidents in North America between 2016-2020, a period of significant change in the CT industry. Examples show how average plug drilling times have generally decreased, with less frequent use of short trips and fewer pipe cycles. The data shows that, for some companies, faster operations have come at the expense of more frequent or severe stuck pipe incidents, whereas other companies have experienced fewer such problems. This comparative analysis illustrates how downhole outcomes can be deduced from surface measurements, and resulting performance metrics can vary widely between companies, fields and geographic regions.
Soroush, Mohammad (University of Alberta and RGL Reservoir Management Inc.) | Roostaei, Morteza (RGL Reservoir Management Inc.) | Hosseini, Seyed Abolhassan (University of Alberta and RGL Reservoir Management Inc.) | Mohammadtabar, Mohammad (University of Alberta and RGL Reservoir Management Inc.) | Pourafshary, Peyman (Nazarbayev University) | Mahmoudi, Mahdi (RGL Reservoir Management Inc.) | Ghalambor, Ali (Oil Center Research International) | Fattahpour, Vahidoddin (RGL Reservoir Management Inc.)
Summary Kazakhstan owns one of the largest global oil reserves (approximately 3%). This paper aims at investigating the challenges and potentials for production from weakly consolidated and unconsolidated oil sandstone reserves in Kazakhstan. We used the published information in the literature, especially those including comparative studies between Kazakhstan and North America. Weakly consolidated and unconsolidated oil reserves in Kazakhstan were studied in terms of the depth, pay‐zone thickness, viscosity, particle‐size distribution (PSD), clay content, porosity, permeability, gas cap, bottomwater, mineralogy, solution gas, oil saturation, and homogeneity of the pay zone. The previous and current experiences in developing these reserves were outlined. The stress condition was also discussed. Furthermore, the geological condition, including the existing structures, layers, and formations, were addressed for different reserves. Weakly consolidated heavy‐oil reserves in shallow depths (less than 500‐m true vertical depth) with oil viscosity of approximately 500 cp and thin pay zones (less than 10 m) have been successfully produced using cold methods; however, thicker zones could be produced using thermal options. Sand management is the main challenge in cold operations, while sand control is the main challenge in thermal operations. Tectonic history is more critical compared with the similar cases in North America. The complicated tectonic history necessitates geomechanical models to strategize the sand control, especially in cased and perforated completions. These models are usually avoided in North America because of the less‐problematic conditions. Further investigation has shown that inflow‐control devices (ICDs) could be used to limit the water breakthrough, because water coning is a common problem that begins and intensifies the sanding. This paper provides a review on challenges and potentials for sand control and sand management in heavy‐oil reserves of Kazakhstan, which could be used as a guideline for service companies and operators. This paper could be also used as an initial step for further investigations regarding the sand control and sand management in Kazakhstan.
Gorski, Dmitri (Heavelock Solutions) | Kvernland, Martin (Heavelock Solutions) | Hals, Knut (A/S Norske Shell) | Blaaflat, Margrethe (A/S Norske Shell) | Ladenhauf, Johannes (OMV, Norge AS) | Aamo, Ole Morten (Norwegian University of Science and Technology) | Sangesland, Sigbjørn (Norwegian University of Science and Technology)
Summary A novel method of utilizing simulations of surge and swab induced by floating rig heave is presented in this paper. The intended applications are in well planning and follow-up of drilling and completion operations. We focus on rig heave during drill pipe connections when the rig's heave compensator cannot be engaged. The method consists of: (1) estimating a dynamic, well- and operation-specific, rig heave limit based on surge & swab simulations at different depths in a well and (2) clearly communicating the dynamic rig heave limit to the rig crew and onshore organization as a simple metric. We present cases where this novel methodology has been tested during the drilling and completion of two offshore wells in Norway, and we elaborate on the operators’ view of the method's advantages. We conclude that complementing the traditional fixed rig-specific heave limit with the dynamic one that is based on the properties of the actual well and the actual drilling/completion parameters offers an opportunity to improve management of risks related to breaching well pressure margins or damaging downhole equipment and to reduce costs through reduction of weather-related non-productive time. We show that the dynamic rig heave limit may differ significantly from well to well and also throughout the same well depending on the kind of operation in the well, depth in the well, well geometry and other parameters related to well and operation properties. Our conclusion is that care should be taken when generalizing a maximum allowed rig heave value as is the industry practice today. The benefits of utilizing dynamic well-specific rig heave limit should be assessed during well planning for any well drilled and completed from a floating rig. Well planning software existing today does not offer this functionality.