Hussain, Sajjad (Schlumberger) | Li, Fei (Schlumberger) | Rana, Vikram (Schlumberger) | Sharma, Varun (Schlumberger) | Dhaher, Karam Sulaiman (Schlumberger) | Blackburn, Jason (Schlumberger) | Haaland, Sigurd (Statoil ASA) | Sivertsen, Atle (Statoil ASA) | Eshraghi, Daniel (Statoil ASA) | Dashtpour, Reza (Statoil ASA) | Lunkad, Siddhartha (Statoil ASA) | Hongdul, Thanong (Statoil ASA) | Bairwa, Girish Kumar (Statoil ASA)
The point-the-bit rotary steerable system (RSS) is frequently used for high-profile directional drilling jobs in challenging environments that require high degree of directional control.
To achieve toolface control, the point-the-bit RSS control system requires two inputs: the rotation rate of the collar (CRPM) and the toolface orientation of the bit shaft. Previously, the tool utilized magnetic field measurements to compute the above two parameters and, subsequently, control the toolface for the well trajectory. However, the point-the-bit RSS steerability is compromised in a blind zone (where magnetic field measurement is significantly interfered with, such as inside casing, drilling out of a whipstock window, or close to offset wells, or does not have enough signal strength, such as in a zone of exclusion (ZOE) where the Earth's magnetic field projection on the cross section of tool is low. The new inertial steering mode of the point-the-bit RSS uses accelerometers and a rate gyroscope sensor to steer the tool, and it can be toggled on or off by a mud downlink. This inertial steering mode effectively expands the operational envelope of the point-the-bit RSS by improving tool steering ability when the tool is in a blind zone or ZOE.
Four successful field runs have been completed on one of the largest mature fields in North Sea Continental Shelf (NCS). In the first field run, the new inertial steering mode of the point-the-bit RSS was used to kick off a well, which is close to seven nearby producing wells, from an openhole cement plug through a 37-m narrow window between the 20-in. casing shoe and 13 3/8-in. casing stump and to drill a 17 ½-in. section in the same run. The new inertial steering mode helped to steer in the desired direction with good tool face control in the presence of high magnetic interference. In the second field run, the RSS tool successfully exited the whipstock window and steered in the desired direction using the new inertial steering mode, providing planned separation from the cuttings re-injection (CRI) zone and drilling the 12 ¼-in. section to target depth (TD). In the third field run, the new inertial steering mode was deployed to exit the whipstock window, drill the 8 ½-in. section to TD, and land on top of the reservoir close to five offset wells with a minimum 14-m center–to-center distance. The fourth field run helped the operator to exit whipstock window inside the 13 3/8-in. casing and steer the 12 ¼-in. section underneath motherbore in a high magnetic interference and collision risks environment.
Based on the four successful runs, the new inertial steering mode of the point-the-bit RSS has been proven for its tool face and trajectory control, expanding the tool's operational envelope.
Our lives depend on reliable energy; if we are to prosper and tackle climate change, society must transition its economies and energy system to meet growing demand and emit less CO2.
Shell believes carbon capture and storage (CCS) is critical. CCS fitted to power plants could be a real game-changer, removing up to 90% of carbon dioxide emissions from power generation.
Engagement and cooperation with different stakeholder groups is key to maturing CCS projects. Shell has worked with stakeholders to help build a strong foundation for some of our CCS projects and this paper will share the approaches applied.
Collaboration is critical to achieving recognition of the scope and value of CCS and achieving acceptance for a specific project. It is important to create engaging outreach and educational initiatives that are targeted to the needs of the stakeholders, demonstrate commitment to local communities, address the points of challenge and clarification, make use of best practice and international project experiences and help bring CCS, energy and climate change to life.
Shell began its community consultation program for its Quest Carbon Capture and Storage (CCS) project in 2008 — three years ahead of filing a project application. A large part of our early consultation efforts were focused on explaining what CCS is, and why the technology is important. Consultation efforts focused on landowners and residents living along the proposed pipeline route and in close proximity to the proposed injection wells, along with the local municipal governments. A community advisory panel has been set up to review data from the Measurement, Monitoring and Verification (MMV) program. The program itself has been reviewed by an independent external expert.
The funding for the Peterhead CCS project has been withdrawn, but we are proud of the relationships established in the early phases of the project's development. The team carried out extensive consultations with the public to keep everybody up to date with plans as they progressed. We proactively sought and received feedback which we then endeavoured to build into our plans.
In addition, strong relationships were built with local, regional and international organisations to develop education-based initiatives around CCS and to build an effective approach to local content on the project, both with the aim of creating best practice learnings for the future.
At Shell, we believe the world will need to find ways to deploy CCS if it is to achieve its ambition to tackle climate change. In order to set CCS projects up for success, we must explore and develop a new model of cross-sector collaboration including: Building an understanding of the local context Engaging early - being present, responsive and inclusive Making communications engaging and relevant
Building an understanding of the local context
Engaging early - being present, responsive and inclusive
Making communications engaging and relevant
Successful engagement, collaboration and community presence can lead to strong, trusting relationships that can be built on over the life of the project.
Ramaswami, S. R. (Shell International Exploration and Production B.V.) | Cornelisse, P. W. (Shell International Exploration and Production B.V.) | Mooijer, M. (Shell International Exploration and Production B.V.) | Kim, I. (Shell International Exploration and Production B.V.) | Elshahawi, H. (Shell International E&P) | Dong, C. L. (Shell International E&P)
The introduction of downhole fluid analysis (DFA) two decades ago was a major addition to the wireline formation testing suite of measurements previously available in the industry, both in real-time to optimize the sampling operations and to provide additional fluid measurements as an integral component of integrated fluid property interpretations. The progression from basic measurements such as fluid resistivity to advanced optical analysis has paved the way for much improved definition of reservoir fluids, including the variation of fluids within reservoirs.
Downhole Fluid Analysis is a continuously evolving field, so we will begin this paper by looking back at the evolution and application of various types of sensors for operational real-time decision making as well as post-operational fluid evaluation. We will then highlight current capability gaps, focusing on the need for improved real-time contamination monitoring in some environments of interest and our desire to measure additional fluid properties and specific species concentrations.
Park, D. (Posco Daewoo Corp.) | Song, I. (Posco Daewoo Corp.) | Bae, Y. (Posco Daewoo Corp.) | Kikuchi, M. (Schlumberger) | Ling, J. P. (Schlumberger) | West, S. (Schlumberger) | Yap, J. (Schlumberger) | Ridho, M. (Schlumberger)
This paper covers the strategies implemented when completing the Shwe gas field in Myanmar. The field, operated by Posco-Daewoo, has been in production since 2013. We present our study and evaluation of the reservoir, integrated completion design, operational challenges, and production performance of the wells.
The project began when Myanmar was subjected to economic sanctions and Myanmar is considered a remote location with quite limited infrastructure, so there were many challenges on the logistics front. The goal of our completion design was to complete the unconsolidated reservoir with either openhole gravel pack (OHGP) or cased hole gravel pack (CHGP), depending on the tendency for water production. The upper completion was designed to optimize gas production. Permanent downhole gauges (PDHG) were installed to monitor the reservoir pressure and temperature.
As part of the development program, eight gas wells and one condensate disposal well were drilled and completed from 2013 to 2015. Logistics and preparation, key contributors to the success of these installations, were supported from Singapore with a limited transit time to the platform, which meant that turnaround time was closely monitored to meet delivery each time. The lower completion project in the 9 5/8-in casing consisted of four OHGP wells and four CHGP wells. Screen type and size, and gravel type and size were determined using particle size distribution studies with core samples and software simulation. Findings were then further verified with extensive lab testing. To achieve minimal skin and damage for the gravel pack (GP) carrier fluid, a nonpolymer fluid was used for CHGP and OHGP. Although a breaker was incorporated into the carrier fluid for OHGP, a filtercake breaker was pumped afterward for maximum cleanup. As for CHGP, the wells were acidized prior to gravel packing. Breakers for the carrier fluid were displaced pre- and post-GP. For the upper completion, five wells with 7-in production string and three wells with 5.5-in production string were completed. After landing the completion string, a formation isolation valve (FIV) was cycled open, followed by well testing. The subsequent pressure matching we performed confirmed that minimal skin and damage were achieved. We achieved and exceeded all the objectives set for the campaign in terms of HSE performance, operational efficiency, production rate, and sand-free production.
Logistics and preparation, key contributors to the success of these installations, were supported from Singapore with a limited transit time to the platform, which meant that turnaround time was closely monitored to meet delivery each time.
The lower completion project in the 9 5/8-in casing consisted of four OHGP wells and four CHGP wells. Screen type and size, and gravel type and size were determined using particle size distribution studies with core samples and software simulation. Findings were then further verified with extensive lab testing.
To achieve minimal skin and damage for the gravel pack (GP) carrier fluid, a nonpolymer fluid was used for CHGP and OHGP. Although a breaker was incorporated into the carrier fluid for OHGP, a filtercake breaker was pumped afterward for maximum cleanup. As for CHGP, the wells were acidized prior to gravel packing. Breakers for the carrier fluid were displaced pre- and post-GP.
For the upper completion, five wells with 7-in production string and three wells with 5.5-in production string were completed. After landing the completion string, a formation isolation valve (FIV) was cycled open, followed by well testing. The subsequent pressure matching we performed confirmed that minimal skin and damage were achieved.
We achieved and exceeded all the objectives set for the campaign in terms of HSE performance, operational efficiency, production rate, and sand-free production.
Sillapacharn, Thitinun (PTT Exploration and Production PLC) | Srichompoo, Sireekorn (PTT Exploration and Production PLC) | Hoonsuwan, Phakhachon (PTT Exploration and Production PLC) | Aroonsangob, Peeradet (PTT Exploration and Production PLC) | Jirarungsakunruang, Sumate (PTT Exploration and Production PLC) | Nitipan, Tunchanok (PTT Exploration and Production PLC) | Vasansiri, Kritithy (PTT Exploration and Production PLC)
It is recognized that several problems, including equipment redundancies and valuable space consumption, exist in the wellhead platform. For example, there are separators installed to separate gas and liquid that come from reservoirs at various operating pressure conditions. The challenge is to integrate these separators in to a single separation unit for space reduction as well as to broaden operating conditions to serve multiple process conditions.
A three-phase test separator together with drain vessels are installed at the wellhead platform in order to execute reservoir management, well monitoring program, and well intervention activities – such as well clean-up during start-up and liquid unloading where gas flow rates are too low for export due to liquid obstructions in well tubing. Furthermore, booster compressor and associate separation system are installed when the wells deplete to the point where they cannot be produced at under natural production conditions. The operation of the booster compressor allows lowering of the wellhead flow pressure and increasing in the reserve recovery factors.
To address the concerns of the oil price crisis and smaller gas prospects in the field, an Innovative Booster Compressor Package has been developed to serve two aspects of value improvement, (i) to minimize an investment cost and (ii) to maximize and ultimate recovery reserve.
To minimize an investment cost, the booster compressor inlet separator and separator blowcase were re-engineered and modified in order to maintain functions of test separator. The gas and liquid flowmeters can work together with an additional watercut meter enabling the determination of fluids flowrate. During the well unloading operation, well fluids entering the inlet separator at very low pressures and will be transported to the export pipeline with assisted gas from the booster compressor discharge line. This modification results in the elimination of the three-phase test separator and the drain system.
To maximize an ultimate recovery reserve, a compressor will either be operated at a high pressure suction with two parallel cylinders, or at a low pressure suction with two cylinders in series configuration. This allows lowering of the abandonment pressure and increasing the recovery factors of these wells. As a result, this swicthable configuration concept can incrase gas protential and assist in sustaining gas production.
A successful development of the Innovative Bosster Compressor has two benefits. First, at least twenty percent (20%) less investment cost is achieved because of the direct cost savings from vessel integration and from topside-area optimization. Second, an estimated ultimate recovery gain from a switchable low pressure booster compressor is expected at about three percent (3%) higher. These are significant efficiency improvements in the economics of the E&P industry.
Zamanuri, A. (Halliburton Bayan Petroleum Sdn. Bhd.) | Abdulhadi, M. (Halliburton Bayan Petroleum Sdn. Bhd.) | Chin, H. V. (Halliburton Bayan Petroleum Sdn. Bhd.) | Lim, C. C (Halliburton Bayan Petroleum Sdn. Bhd.) | Jacobs, S. (Halliburton Bayan Petroleum Sdn. Bhd.) | Sayed Zainaiabidin, S. M. A. (Petronas Carigali Sdn Bhd) | Khalil, M. I. M. (Petronas Carigali Sdn Bhd) | Abd Wahid, M. I. (Petronas Carigali Sdn Bhd) | Dolah, K. A. (Petronas Carigali Sdn Bhd) | Munandai, H. (Petronas Carigali Sdn Bhd)
In a mature oil field that has been producing for over 30 years, declining reservoir pressure and increasing water-cut are the two major factors that are affecting oil production rates. It is a common understanding that without any effort, this decline in oil production will remain until the end of the field's economic life. One of the approach to address this issue is through production enhancement work which has been proven successful in an oilfield offshore of Sarawak not only at arresting the overall field decline, but also increasing the overall oil production.
The practice for Production Enhancement (PE) work in this field mainly involves (i) shutting off the existing watered-out intervals, (ii) adding perforations to the existing sand and/or a different reservoir, (iii) zone change and gas lift valve change activities, (iv) re-activation of idle wells, (v) gas lift optimisation and well bean-up, (vi) reservoir management planning and (vii) restoring well integrity.
Due to the limited deck space on the platform and the unavailability of living quarters, the application of a work barge was essential for this type of PE work to house the necessary equipment and chemical for the enhancement job as well as acting as an accommodation vessel for the personnel. Concurrent well intervention operations on two different platforms was the selected option for time and cost optimisation and quicker first oil. For the same reasons, 24 hours operation was implemented whenever circumstances permitted. Further cost optimisation was implemented in subsequent campaign by utilizing slickline only as means of well intervention as well as withdrawing the option to have a dedicated work barge on site to support the campaign.
After the successful PE Campaign in four (4) consecutive years, this initiative has resulted in over 3500 bopd of incremental oil. The overall technical potential (TP) of the field also increased by more than 100 percent. This has effectively arrested the previously estimated 25 percent field decline before the campaigns and increased in the overall field production. This paper seeks to present the challenges, the plans and operational execution of the well intervention activities. The results of the successful PE campaign, implementation of best practices, lessons learnt and improvement plan will also be shared.
It is increasingly important that decision makers for large capital projects (including development and decommissioning project phases) evaluate all project alternatives to determine the optimal final project configuration. The decision making process must take into account several important aspects including the long-term environmental impact or benefit of various project alternatives. Determination of the optimal project alternative often has long-term cost implications. In recent years, several innovative tools have been developed to streamline and optimize the decision making process. One of those is the use of the Net Environmental Benefit Analysis (NEBA) to determine the environmentally superior project alternative.
Here we utilized an innovative approach to the NEBA process by developing a semi-quantitative model that provides a relative ranking of project alternatives based on the expected environmental benefit. Our use of NEBA includes evaluation of initial project impact, impact recovery rate, and final (i.e., post-recovery) benefit level for each considered project alternative. The NEBA tool utilizes a streamlined approach designed to rely on a consensus scoring approach to various project attributes. The results of the model provide a relative ranking of project alternatives based on their net environmental benefit and irrespective of project cost or other considerations. In this respect, our approach provides a "pure" environmental vision of the project. As a consensus approach it is ideal for use in workshop formats with stakeholders and regulators avoiding lengthy iterations to determine a project outcome.
Our case study is made to rank five different project alternatives for offshore platform jacket decommissioning following evaluation of ten environmental aspects. Specific environmental aspects considered include the physical and chemical quality of air, water, and sediments at the project location. The ecology of marine fish, benthic organisms, mammals, and seabirds are also considered as are impacts to fisheries, coastal and terrestrial ecology. We bounded impact recovery rates to 100 years and evaluated five different recovery slope factors in the NEBA model. Following application of scoring and specific weighting factors to each environmental aspect, a quantitative NEBA score was developed for each project alternative evaluated. The result of our NEBA approach was a quantitative ranking of project alternatives in the context of the environmental benefit of each approach.
Our approach provided a comprehensive evaluation of project alternatives and returned a clear environmentally superior project alternative. The results of this approach provide project development decision makers with a cost effective and efficient tool to make defensible decisions to choose the most appropriate project alternative.
Today, oil and gas industries have been continuously drilling into deeper reservoirs and into high temperature formations. Drilling high temperature wells poses new challenges with current available drilling tools because the operating temperatures can closely reach and at times, surpass downhole tools' temperature specifications. The temperature will affect electronics, elastomer or rubber components in tools, sensors, or even could reduce the mechanical strength of the steel collar and cause twist-off. The development of downhole tool technology continues to strengthen and increase the tool temperature rating to withstand those challenges. Utilizing high temperature rated downhole tools can be significantly expensive compared to standard temperature rating tools (150oC). Other technological developments for high temperature wells rely on mud properties and mud surface cooling system. Despite that, one of the key factors to successful drilling operations in high temperature wells still lies on the capability to simulate downhole conditions taking account various technologies and parameters involved, understand the potential challenge and risks, and predict down-hole circulating temperatures that tools will be exposed to.
This paper presents an emergency well killing operation using rig less Coiled tubing unit intervention in a highly erosive environment. Conventional killing operation had resulted in severely eroded and punctured coiled tubing due to sand ingression and subsequent killing failure previously unseen in OIL's areas of operations. This called for reconsideration and alterations to conventional methods using the same available equipment and thereby successful killing of the well.
Sand ingression though common in OIL's oilfields had never previously compromised well completion to such degree. Well no. "DHL" was a gas producer producing 40000-50000 SCUMD of gas. Pressure build-up of 170 ksc was noticed in tubing, 5 ½" casing annulus and also in 9 5/8" casing annulus. Hole-probe survey of the well showed sand and mud build up. Subsequent MIT log survey of the well showed corroded and severely damaged completion. This rendered the well incapable of being killed by conventional methods of killing. Coiled tubing unit was deployed and it was tried to kill the well. However the first attempt failed to subside the well pressure and upon pull out severe pitting of the coiled tubing surface and tubing puncture was encountered due to the sand ingression. Alterations were thereby made in the circulation procedures and successful killing of the well was achieved for remedial work over operations.
Gas well killing is always critical and such conditions of compromised completion, sand ingression and erosion coupled with abnormal pressure build up further adds to the criticality and safety hazards. However with intelligent thinking the job may be achieved with the same resources saving costly man-hour, runtime of machine and downtime of reservoir. Coiled tubing thus proves to be a versatile tool for intervention in wells where regular methods are no longer feasible. In addition to this, with minor tweaks using the same equipment, such critical operations may be carried out as well which might seem unachievable at first.
Yu, Hongyan (Shaanxi Key Laboratory of Exploration And Comprehensive Utilization of Mineral resources, State Key Laboratory of Continental Dynamics, Geology Department of Northwest University, Research Institute of BEG, CNPC) | Wang, Zhenliang (Geology Department of Northwest University) | Rezaee, Reza (Department of Petroleum Engineering, Curtin University) | Zhang, Yihuai (Department of Petroleum Engineering, Curtin University) | Xiao, Liang (China University of Geoscience) | Luo, Xiaorong (Institute of Geology and Geophysics & Key Laboratory of Petroleum Resource Research, Chinese Academy of Science) | Wang, Xiangzeng (Shaanxi Yanchang Petroleum Group Co., Ltd) | Zhang, Lixia (Shaanxi Yanchang Petroleum Group Co., Ltd)
Total organic carbon (TOC) estimation is very important for shale gas reservoir characterization. There are many introduced methods for TOC prediction in organic-rich shales. However, there are still some weaknesses with the most of the methods. This paper proposes a new method using machine learning, Gaussian Process Regression, which is expert in processing high-dimension, small samples, and non-linear problems. Compare to the Neural Network, and Support Vector Machine, Gaussian Process Regression has adaptation and generalization ability. This paper takes Zhangjiatan shale of the Yanchang Formation of the Triassic period in the south-eastern Ordos Basin as an example. A total of 7 kernel functions are applied to build the regression model. As a result, the Cauchy kernel is chosen due to lowest error. Then, feature selection is carried on based on the weights which calculated from 4 weights algorithms. Finally, compared the Gaussian Process Regression results to the traditional methods, (e.g., Passey and Schmoker methods), we found that Gaussian Process Regression works well for TOC estimation.