bluuebunny/crossref_metadata_2025 huggingface dataset:
Openness in Reservoir Simulation: Empowering Flexible Field Management
Authors: Zhou Wentao , Ali Samad , Biniwale Shripad
Published: November 2020

As the oil and gas industry enters the digital era, openness is a key enabler to realizing the vision of transforming the industry for the better. The practice of reservoir engineering and reservoir simulation is no exception. In this paper, an openness mechanism in a reservoir simulator using Python scripting language is introduced. It empowers engineers to utilize simulation in new ways. It extends simulator capabilities and enables people to implement flexible-control logic to solve field management challenges.

The new openness mechanism in the simulator allows engineers to program and include Python scripts in a simulation model. These scripts interrogate and interact with the simulator. The scripts are executed by the simulator while running the model. Flexibility is available to execute the scripts at every Newton iteration, before and after every simulation timestep, at specified times, or when a criterion is met. Simulation model properties can be queried through the scripts, such as well connections, well properties, group properties, grid region properties, network entities, current simulation time, etc. The scripts can set properties such as well constraints, well and connection productivity index (PI), group production target, pausing or stopping the run, etc. Customized control logic, if not directly available in the simulator, can be implemented in the scripts that interrogate and drive the simulator. Such customization can be packaged as Python libraries and shared with team members, enabling continuous value creation. Public Python libraries, such as NumPy, pandas and pywin32 or win32com, can also be loaded in the scripts to extend even further what the simulator can do.

The openness mechanism is demonstrated on case examples. They include customized action to acidize wells when production drops, approximating the geomechanical effect of decreasing well pressure, modeling the effect of fines in injected water on well injectivity, and connecting to a network simulator. Examples are also given on customized reporting for model diagnostics and result interpretation, setting production constraints based on economics calculated in an Excel sheet with complex fiscal regime, advanced gas accounting, management of sulphur content, dual-optimization to meet gas demand while honoring oil treatment capacity, and integrated asset modeling from reservoir to surface networks to processing facilities.

the ability to extend built-in functionalities of a reservoir simulator and customize field management controls using user scripting language. It embraces innovation and enables continuous value creation in reservoir simulation.
Intelligent Completion Implementation in Immiscible WAG Wells in a Mature Offshore Field EOR Project
Authors: James Berok Sylvia Mavis , Sinanan Haydn Brendt , Tan Chee Seong , Kalidas Sanggeetha , Goh Gordon
Published: November 2020

As part of the enhanced oil recovery (EOR) field development plan (FDP), four immiscible water alternating gas (iWAG) wells with intelligent well completions were successfully completed. Inflow control valves (ICV) with dual-permanent downhole gauges (PDG) in each zone were installed to allow remote injection control and monitoring. Each well has three zones. One of the iWAG wells was installed with the DTS cable behind casing. This enabled the injection profile monitoring across each sand in order to optimize the injection rate distribution and representatively amongst the four wells. The paper further discusses the injection strategy to meet the required zonal injectivity and reservoir zonal voidage replacement over field production life.

Downhole water injection conformance is critical for managing thin oil rim reservoirs. The injection plan considered several factors including uneven zonal split injection, short-circuiting injector to producer issues, and unfavourable zonal water-front propagation and changing injection scenarios over time. Hence, zonal control with optimal valve design is critical in achieving the EOR reservoir management plan. Injectivity and conformance modelling was performed on four iWAG wells across three reservoir zones to ensure optimal valve-sizing configuration for comingled injection multizone. A base case simulation assuming no downhole zonal control (all zones fully open) was first performed to understand the zonal injection performance and distribution contrast for both water and gas injection. This subsequently served as a guide for the zonal injectivity control strategy. This was followed by modelling valve sizes across a variety of injection scenarios. This was done to ensure the design working range for balancing future zonal injection selectivity under expected uncertainty range.

Post deployment ICV modelling was performed with cross-reference to actual petrophysical data, reservoir properties, and well trajectories. Petrophysical evaluation showed some zones are having lower permeability with low fracture pressure. Step rate injection test data was used to calibrate the model and to further validate whether the valve sizes were within the design ranges prior to the injection phase. Based on the simulation using surface injection rates and PDG pressure data, most of the zones were able to meet the target injection rate within the set fracture pressure. The model will then be further updated with the zonal injection data in the future as the iWAG injection program is implemented.
Improving Well Delivery by Integrated Geomechanical Understanding with Robust Well Planning and Execution: A Successful Case Study from a Development Drilling Campaign in Offshore Peninsular Malaysia
Authors: Tello Roberto Horacio , Wong George , Ghosh Amitava , Chatterjee Avirup , Santhamoorthy Priveen Raj
Published: November 2020

This paper presents a case study on usefulness of having geomechanical understanding to avoid drilling risks and minimize costs in a Drilling campaign, Offshore Peninsular Malaysia.

Significant drilling issues related to wellbore stability were encountered in the four exploration wells drilled during previous campaigns. The development wells were planned to drill with high inclinations (up to 700), through weak coal layers and cross major fault. The drilling problems of the offset wells were critically analyzed to understand the mechanisms of failures. A geomechanical model was built using the offset well information. The well-calibrated stress model was then used for the wellbore stability modeling for the planned trajectories. The outcome of this study was used as key input for casing and mud design.

With the help of the reccomendations based on this study, six highly inclined development wells were drilled through low pressure and narrow mud window intervals without operational problems. Reducing non-productive time (NPT) for the entire drilling campaign was one of the key focus for delivering the wells safely within schedule and budget. This paper documents the entire workflow and methodologies used for this entire study.
First Offshore Hydraulic-Jet-Fracturing Multizone Completion Application Case Study: Challenges and Lessons Learned in the Bozhong Oil Field, Bohai Bay, China
Authors: Fu Jianmin , Ma Yingwen , Zhang Ming , Ma Changliang , Liu Zhengwei , Zhou Shubo , He Lei , Feng Liang
Published: November 2020

The first hydraulic-jet-fracturing multizone completion application was performed in an offshore high-permeability oil well located in the Bozhong oil field in Bohai Bay, China. A detailed case study is presented, highlighting operational challenges and lessons learned from the offshore multizone completion in the Bozhong field.

Most offshore high-permeability oilwell completions in the Bozhong field employ tubing conveyed perforation (TCP) followed by frac-packing as multi-zone completions, which is practical in this field. Unlike conventional multizone frac-pack completions, to run perforation guns, the perforating must be completed first, followed by running isolation packers to complete the multizone frac-packing treatments. For hydraulic-jet-fracturing multizone completions, the hydraulic jetting tools are delivered to the target depth using drill pipe; following that, slurry fluid is pumped through the drill pipe to cut through the casing to create fluid flowing channels, which communicate with the pay zone formation. Lastly, the fracturing operation is completed by pumping both proppant slurry through the drill pipe and cleaning fluid through the annulus simultaneously, which creates dynamic hydraulic diversion as functions of isolation between zones. After completing one treatment zone, the tools are pulled to the next target depth, repeating the procedures, until the entire well is complete. After the fracturing treatment, the operator runs production tubing and other accessories, putting the well into production as usual.

A detailed completion design and step-by-step operational procedures were prepared based on well data and work conditions to help ensure the effectiveness and safety of the offshore operation. Although some challenges were encountered during the operation, it was overall successfully performed, and significant performance improvement was achieved. After being in production for months, the candidate well has maintained a longer high-production-rate period than the offset wells completed using conventional multizone frac-pack completions.

This hydraulic-jet-fracturing multizone completion has proven successful in the Bozhong oil field. The experiences and lessons learned can help benefit future multizone completion optimization for other similar offshore high-permeability oil wells.
Multi-modal Particle Size Distribution of Lost Circulation Material Blend for Controlling Fluid Losses from Multiple Fractures Around Inclined Wellbores
Authors: Nguyen Kien , Mehrabian Amin , Santra Ashok
Published: November 2020

Lost circulation material (LCM) is commonly used to stabilize formations and inhibit fluid losses from the wellbore during drilling. Mud loss records and wellbore downhole image logs often reveal existence of multiple natural and drilling-induced fractures in the wellbore vicinity. Appropriate particle size distribution (PSD) for the LCM blend should be designed so that lost circulation from all near-wellbore fractures is contained.

This paper presents a novel design scheme for multi-modal PSD of LCM blends applicable to the likely cases of lost circulation from multiple near-wellbore fractures. The design scheme takes advantage of an analytical solution which estimates the fracture widths of an arbitrary number of fractures around inclined wellbores when subjected to the three principal stresses of the subsurface. The LCM blend design involves dividing the blend into subcategories of various sub-blends sizes. Each sub-blend has distinct particle size distribution, when combined, satisfying the size distribution criteria on the quantile distribution basis. The fractures apertures widths, which are a crucial input for LCM blend selection, are determined from an analytical solution of the related wellbore geomechanics problem. The solution is derived from the dislocation-based formulation of fracture opening profile in an infinite poroelastic medium. The effects of overburden stress, anisotropic horizontal stresses, wellbore inclination and azimuth as well as the mechanical interaction between the cracks are incorporated in the analysis. Further, a systematic method to characterize mud cake parameter is employed. Mud cake efficiency is shown to cause considerable influence on fractures aperture width and consequent composition of the LCM blend.

A synthetic study case mimicking typical depleted sand drilling environments is used to determine the optimal LCM blend design. The poroelastic back-stress effect is considered in the test cases, suggesting substantial changes in fracture initiation pressure and fractures apertures compared to the corresponding elastic solution. Furthermore, the sensitivity of fractures widths to geomechanical parameters is analyzed. The results indicate an interesting interaction between fractures as they induce a compressive hoop stress on one another, limiting the width growth of other fractures. Consequently, the multi-fracture wellbore problem introduces a variation in fraction width, thus causes different LCM sub-blend recommendations tailored to individual fractures. A combination of these sub-blends, each of which only covering a narrow range of fracture width, suggest a novel treatment of fluid loss in multi-fractured wellbore by forming a super-blend which covers the whole range of width distributions.
Pressure Wave Downhole Communication Technique for Smart Zonal Water Injection
Authors: Wang Quanbin , Jia Deli , Hu Gaixing , Sun Fuchao , Zhang Jiqun
Published: November 2020

Zonal water injection technique has been proved an effective method for enhanced oil recovery of multi-layer heterogeneous oil reservoirs. Higher zonal injection qualified rate is an important index for improving the effect of waterflooding development, so frequent monitoring and adjusting flowrate of separated layer is necessary. However, when traditional zonal water injection techniques are used, periodic flowrate testing and adjusting are realized by an armored cable with steel wire, which lead to a large number of testing work. This paper proposes a smart zonal water injection system based on pressure wave downhole communication technique. In this system, an integrated water distributor and a wellhead control device with pressure sensor and flow regulated assembly is developed. Continuous pressure wave can be generated by controlling the opening of downhole water distributor and wellhead control valve, and the pressure changes in wellbore can be monitored by sensors. Based on the time shift keying coding and decoding techniques, control command and downhole monitoring data are loaded into the continuous pressure wave. The pressure wave communication between wellhead control valve and downhole water distributor can be realized with injection water as the medium. With the help of General Packet Radio Service (GPRS) and Internet technology, the smart system can also be used for remote monitoring of downhole parameters and remote regulating of zonal flowrate. The smart technique for zonal water injection wells has been implemented in 89 wells in China National Petroleum Corporation (CNPC) Changqing M1 Block. Testing and adjusting work by testing vehicle in traditional zonal water injection technology is eliminated. The results of 27 tracked wells show that the maximum effective distance of pressure wave communication is 2879 m, the minimum pressure change that can be identified is 0.5 MPa, and the time of uploading a flowrate data takes 70 min. The effect of waterflooding development is improved after applying the smart technique. Zonal injection qualified rate is improved from 63.6% to 90.3%. Reservoir water absorption thickness is increased from 18.5 m to 19.4 m. Reserves producing degree of waterflooding development is improved from 68.7% to 70.2%. Natural decline rate is reduced from 5.2% to 4.8%. This paper illustrates a technology of pressure wave downhole communication for smart zonal water injection and an integrated case study, which can obtain vast amounts of real-time pressure data, and help reservoir engineers adjust development plan of waterflooding reservoirs. In addition, it offers a methodology for downhole wireless control.
Using Distributed Temperature Sensing to Inform the Quality of Cementing Operations
Authors: Ricard Ludovic Paul
Published: November 2020

Surveillance of well work-overs and downhole operations is not trivial but is becoming increasingly feasible with recent improvements in the technology of fibre optics. Well cementing operations are critical for providing zonal isolation over the life of a well. However, there are limited downhole options to monitor and inform operations in real-time. Installing a permanent fibre optic cable enables surface to reservoir permanent surveillance. In this work, fibre optic cables were deployed in 4 different wells using different configurations and test passive and active distributed temperature sensing (DTS) setups to interpret the quality of the cement injection and hydration processes.

Well cementing can occur during well installation and decommissioning. For 3 wells, fibre optic sensing cables were installed for the purpose of monitoring the casing cementing installation, detect zones of isolation and any background lateral flow in the formation.

For one of the well, fibre optic cables were installed inside casing to monitor a full wellbore decommissioning cementing operation. Following the same process, datasets were acquired prior to and during cement injection.

Dataset acquired during mud circulation highlights interval of thief zones and potential leakage zones for the cement into the formation. The real-time surveillance of cement injection informs about the top of cement but also the in-fill of breakout intervals and the blockage of thief zones.

The long-term surveillance of the vertical temperature distribution enabled to determine the timing and intensity of the cement hydration process and provided a unique insight on the quality of the cementing operations and its possible correlation to breakout intervals and thief zones.

Active DTS was also used to confirm the completion installation as temperature diffuses differently depending on the presence or absence of gravel pack and the thickness of the cement sheath.

Our results show that downhole surveillance of cementing operations is possible using DTS. This technology enables high vertical accuracy in real-time and long-term surveillance providing insights on the quality of the cement bond. In this case study, DTS has proven to be a very valuable and reliable tool throughout the cementing operations at 4 wells.
A Case Study of Continuous Improvement: Successes and Challenges of the Norton Multi-Lateral Development
Authors: Dutta Brijesh , Cahill Quinton , Negrini Victor , Jelly Christian , Butler Ben , Kent David
Published: November 2020

The recent, sustained depression in global oil prices has driven a significant reduction in upstream Exploration and Production (EandP) expenditure, particularly in the capital-intensive offshore environment. The high costs traditionally associated with EandP development projects, specifically in subsea developments, have driven a requirement for the adoption of technologies that not only increase the efficiency of the well construction process, but also reduce the total number of wells required, whilst increasing production rates and recoverable reserves.

Building on recent industry experiences with the varying multilateral systems available, Woodside implemented the use of an alternative innovative multi-lateral system, which has gone through multiple evolutions and marked improvements in system reliability and installation efficiency compared to Woodside's previous multilateral experience. The latest evolution of this system has been implemented during the construction of multi-lateral wells for the Greater Enfield Project (GEP). Within GEP, the Norton over Laverda (NoL) field development comprises three tri-lateral production wells (namely NoL01, NoL02 and NoL03). Norton field is an offset to the Vincent field, which employed an alternative multi-lateral completion design. On average, the Norton multi-lateral well operations were executed 15-30% faster than previous comparable Woodside installations. This has been attributed to the application of operational learnings from the previous Vincent multi-lateral development and the implementation of the new system. These wells were constructed in water depths of > 800 m, the deepest for such a system globally. Of the three wells, NoL01 and NoL02 were constructed well under budget, and ahead of schedule. NoL02 was constructed in a time that benchmarked as the fastest well per 1,000 m versus basin offsets. NoL03 was completed within budget, whilst having faced two major NPT (Non-Productive Time) events (ultimately resolved using world first solutions for the given system). This paper will discuss the successes, challenges experienced, and lessons learned during the installation of the three Norton tri-laterals. This field is a prime example of how new technology and the installation practices for multilateral systems within the operator's assets of the North-West margin of Australia have improved over time.
Well Integrity-Sealant Pressure Barrier for High Delta P, V0 Sealing and Long Durability
Authors: Shan Youngbin , Gao Wenxiang , Wang Xuelong , Xu Minglei , Cao Cong , Zhang Chao , Du Hai , Jin Xiaohu , Su Xiaodan , Wang Wenxiong
Published: November 2020

It is a great challenge for well integrity when a high volume gas production well is found with the production casing broken near the wellhead hanger resulting in high pressure communication between Annulus A and B.

The objective of the paper is to propose a new solution to establish a strong pressure barrier between annulus via a sealant system and to show that such a barrier has been proven to be durable for long time.

A proprietary resin sealant is the key technology and precise job planning and execution are also viewed as being vital to the success of treatments.

Because tubing flow pressure may reach up to 10,000 psi during production after recompletion, operator decided to pressure test the sealant barrier to 10,000 psi for a minimum of 30 minutes duration. If pressure drop during the pressure test is less than 100psi, then the well is allowed to be recompleted.

Several spots and squeezes of sealant eventually setup a strong pressure barrier and were pressure tested up to 10,000 psi in both A and B Annuli. There was no pressure communication at the other annulus in the 30 minute test period.

In the past six (6) years, the operator has tried several jobs to repair casing leaks but none were successful. It was the first time that a sealant system provided a solution to repair a casing leak and hold a high pressure differential.

During recompletion, the production packer failed to set but the operator decided to initiate production. A annulus pressure increased quickly and finally stabilized at 8700 psi. It is now a year since the job was completed in October, 2019, and B annulus pressure in has consistently remained at zero pressure. This has proved that the sealant technology can securely setup and provide a high pressure barrier which is valid for long term V0 sealing.
Evaluation of CO2 Injectivity for CO2-EOR Using a Two-Stage Well Test Approach: Case Study of a Chinese Tight Oil Reservoir
Authors: Honari Vahab , Wang Xiangzeng , Underschultz Jim , Garnett Andrew , Wang Xingjin , Johnson Raymond , Ribeiro Ayrton , Sedaghat Mohammad , Gao Ruimin , Liang Quansheng , Hurter Suzanne
Published: November 2020

CO2 geo-sequestration can significantly contribute to the reduction of greenhouse gas emissions. Out of all geological CO2 storage sites, mature oil fields are often considered primary targets for CO2 sequestration as one of Carbon Capture, Utilisation and Storage (CCUS) approaches where the operation cost can be offset by enhancing oil recovery and utilising the existing facilities. However, a geological formation with large volumetric capacity (pore volume) is not necessarily an appropriate candidate for CO2 storage and CO2 injectivity plays equally an important role for site selection to store CO2. Therefore, evaluation of CO2 dynamic storage capacity (injectivity) and ultimate CO2 enhanced oil recovery (EOR) are key elements for a successful CO2 storage – EOR project.

CO2 EOR was considered as a suitable tertiary oil recovery approach after very short and inefficient primary and secondary oil recoveries in Yanchang oil field, the second largest tight oil field in China, located at Ordos Basin in north western China. This paper describes the acquisition of essential dynamic data from a reservoir in Yanchang oil field to evaluate its CO2 injectivity/dynamic storage capacity. For that, numerical reservoir simulation was utilised to model and history match the target reservoir. The history matched model was then used to numerically perform several testing scenarios resulting in the selection and design of the most appropriate test.

A unique two-stage well testing approach was proposed to inject water and CO2 into one well and observe the pressure at two monitoring wells for a total testing period of about one year. It accurately estimates formation effective permeability in both the water flooded zone (test stage 1) and the CO2 flooded zone (test stage 2) at the injecting well. Also, it qualitatively estimates the water and CO2 fronts in the reservoir as well as CO2 injectivity using data at the injecting well. The radius of investigation (ROI) significantly increases by adding two monitoring wells to the existing injecting well. Using two monitoring wells also identifies heterogeneities and lateral anisotropy in the reservoir. The recently acquired field data, as part of this well testing program, indicate that the reservoir characteristics at the monitoring wells are significantly different from each other, suggesting the existence of considerable heterogeneity/anisotropy in the reservoir.

The results generated by this well test are included in the reservoir model to reduce uncertainties for the future CO2-EOR field development plan. Finally, more informative decisions can be made on whether or not a field is suitable for a CO2-EOR project to unlock further oil resources from tight formations.
Validation of a Novel MEG Sensor Employing a Pilot-Scale Subsea Jumper
Authors: Kumar Asheesh , Di Lorenzo Mauricio , W. E. Norris Bruce , Lupeau Alexandre , Solheim Harald , M. Aman Zachary
Published: November 2020

Online pipeline management systems provide real-time and look-ahead functionality for production networks. However, they are limited by a dearth of data to inform their predictions. This represents a barrier to a true, high-fidelity ‘digital twin’ where greater integration with new sensor technologies is needed to bound model predictions and improve their reliability. In this work, we present a novel MEG (Mono-ethylene glycol) sensing system from OneSubsea, the AquaWatcher v2.0, and validate it in our newly-constructed HyJump flowloop.

The HyJump flowloop has a unique subsea jumper-like geometry, with three low points and two high points and is equipped with a MEG sensor - mounted on the second low point. The sensor features an open-ended microwave frequency probe mounted flush to the pipe wall which measures the apparent permittivities of the liquid phases in the vicinity of the probe tip. It can determine the MEG concentration or water salinity by processing the measured permittivities, and has further shown that it may be able to detect hydrate deposition. Experimental work was performed to test the performance of this novel equipment while enabling a more accurate calculation of the overall mass balance in the flowloop.

An experimental campaign was conducted where, in each measurement, the jumper low points were loaded with aqueous solutions of MEG at mass fractions between 10 and 30 wt%. The entire loop was then pressurized with Perth city natural gas to 1200 psi. The pipe wall temperature was controlled with a cooling jacket in the range of 25.2 °F to 35.6 °F. These conditions simulate transient shut-down and restart operations with a high probability of hydrate formation. Results illustrate that the MEG content readings measured by the sensor were consistently accurate within a 5% relative deviation with respect to the nominal values. Further, flow restrictions due to hydrate deposition were assessed in their severity through differential pressure measurements, where it was observed that the measured MEG content oscillates significantly during hydrate sloughing-type events.

The HyJump flowloop facility offers a unique testbed for new subsea sensors, enabling performance evaluations with internal fluids at subsea conditions. The deployment of these novel sensors in the field will both improve the performance of integrated pipeline management solutions and assist operators in optimizing MEG injection dosages to enable higher fidelity hydrate management in subsea pipelines.
Middle East to India Pipeline
Authors: Nash Ian , Rawlings Matthew
Published: November 2020

This paper presents details of a comprehensive array of technical and commercial challenges associated with the feasibility of a long distance deepwater Middle East to India Deepwater Pipeline (MEIDP) providing information on the technical and commercial feasibility of the deepwater gas transportation system, which will reach a record water depth of 3450m, cross two continental slopes, an earthquake subduction zone (the Owen Fracture Zone) and outfall debris of the river Indus fan in 2500m water depth. It examines the techniques, analysis and technology development now available to make such challenging routes increasingly feasible.

The economic and political drivers for such a project are presented together with details of the overall project cost and tariff calculation to allow successful gas utilization by India's gas starved and stranded power stations. The challenges faced by the project from both a design and installation perspective are discussed together with some of the detailed geohazard assessments performed for the pipeline crossing and active fault zone (OFZ) and the Indus Fan.

High pressure trunk lines have proved to be the safest, cheapest way of transporting gas to market for short to medium distances up to 2,500 kilometers, making the proposed SAGE - Middle East to India Deepwater Pipeline the optimal solution for gas delivery to the Indian Subcontinent. Linking Middle East gas fields of Saudi Arabia, UAE and Oman to India across the Arabian Sea for an offshore distance of 1200 kilometers. The MEIDP gas transmission pipeline is designed to transport up to 1.1BCFD gas into the Indian energy markets.

The qualification plan developed with DNVGL is described together with details of the future construction schedule for first Gas. The Middle East to India Deepwater Pipeline
Gorgon Produced Water Treatment and Disposal: Commissioning and Operating a Vital Part of LNG Production
Authors: O'Reilly Daniel , Yee Boniface , House Andrew
Published: November 2020

The Gorgon gas plant produces 15.6 Million Tonnes per Annum (MTPA) Liquified Natural Gas (LNG) from the Gorgon and Jansz-Io subsea gas fields. First LNG production commenced on the Barrow Island, Australia facility in 2016. One of the first systems commissioned was the wastewater treatment, collection and disposal system, a critical support utility for production operations. The Produced Water Disposal (PWD) facility is unique on Barrow Island due the location's national nature reserve status, and all treated waste must be disposed downhole. The objective of this paper is to review key lessons from design, startup and steady state operations. Perspectives will be given on facility/well management and production operations of PWD at the Gorgon plant.

Wastewater on Barrow Island is generated from several sources: Condensed water originating from hydrocarbon gas (separated at gas dehydration and Mono-Ethylene Glycol (MEG) regeneration facilities), drainage and runoff water from the plant, treated sewage effluent and other ad hoc liquid waste. These sources are collected and treated before the final product is pumped into two available onshore disposal wells. One of the challenges initially faced was that the disposal water quality did not meet the design specification required to maintain well performance. This problem reduced as the plant reached steady state operations and the team gained a better understanding of well performance over time. Other current challenges include hydrocarbon carryover and water polishing, so Engineering and Operations work together closely to ensure reliable water disposal and hence LNG production.

This case study will explore the success and lessons learnt in Gorgon PWD through a summary of field data, facility descriptions and experiences. An overview of the design will be given along with photographs of key components. The required design performance will be compared against actual operating data. In the new energy landscape, the Upstream Operators' social license to operate centers around our environmental performance. In our work we demonstrate that it is possible to treat and dispose of waste liquids responsibly while generating cashflow through LNG production.
Well Abandonment Efficiency Improvement through Collaboration!
Authors: Obodozie Ikenna , Blakeman Philip , Knox Brendan , Hutama Aditya , Firdaus Lutfy
Published: November 2020

The operator, rig contractor and services company formed a trilateral collaboration to plan the safe plug and abandonment of four onshore wells located in a densely populated region of Indonesia. These wells, located in scattered locations, posed a significant logistical challenge for project mobilization and moves between the wells. Well information was incomplete due to a change in asset ownership.

Some of the challenges faced in these wells were: Well integrity issues resulting from the presence of H2S and CO2Sustained casing pressureSurface water safetyFluid losses

Personnel safety and future well integrity was crucial to this operation. Consequently, plans were developed to conduct the operation safely and efficiently, as well as to provide solutions that mitigated well integrity challenges.

The method adopted for this project was to approach this as an integrated project where the collaboration team was responsible for planning, executing, monitoring and closing out all segments of the project. Well information from the previous field operator was analyzed and a solution to safely plug and abandon these wells was created. Because inadequate well information posed a major challenge, the collaboration team planned multiple contingencies. An abandon-the well-on-paper (AWOP) workshop was organized to review and refine the execution plan.

An intelligent coiled tubing system, which could be used for simultaneous logging and pumping operations, was selected as well as an efficient and environmentally friendly mechanical pipe cutter that did not use explosives or hazardous chemical substances for tubing severance operations. The sustained casing pressure challenges (in previously fully cemented/non sealing annuli) were addressed by using advanced milling technology for section milling.

The early engagement plan enabled development of a project execution strategy that clearly outlined equipment mobilization schedules from various locations in Indonesia. Because of the collaborative projects structure, local personnel recruited for this project were quickly on boarded and integrated with the rest of the project team. This approach led to the safe and efficient execution of the plug-and-abandonment scope of work, with zero HS&E incidents and 167 perfect HS&E days during project execution.

Extensive testing of cement mix water was introduced to this project. The testing improved the cement design and enabled accurate plan transition times that reduced waiting on cement. Based on lessons learnt from the first well, extensive logging operations were performed to determine the formation temperature and specific leak locations in the casing. These pre-cementing logging operations helped in collecting accurate well temperature and pressure information that aided the design of cement recipes for the barriers placed in these wells.
A Novel Application of Filter Cake Remover to Free Differential Stuck Pipe
Authors: Egbe Peter , Al-Mousa Fawaz , Gadalla Ahmed
Published: November 2020

Historically, stuck-pipe events have been shown to cost the industry several hundred millions of dollars per year, and over 30% non-productive time (Muqeem et al. 2012). In all cases, remedial operations to salvage the subject well are expensive; and success is not guaranteed. This paper describes a case history demonstrating how a differentially stuck string was freed in a relatively short time using an innovative enzyme/weak acid recipe.

The string was a 4-1/2 in. lower completions bottom hole assembly (BHA) comprising of swell packers, and inflow control devices. The string was deployed in a carbonate reservoir. After deploying the string in the first 1,000 ft of open hole, the crew stopped to fill up the string to confirm circulation. Upon resumption of operations, the completions string was found to be stuck with no string movement possible in the upward or downward direction. Full circulation was still achieved. The fluid in hole was a water-based fluid.

The string was diagnosed to be differentially stuck. It was established that the stuck point was across the high permeable zone. Efforts to work the string free with glycol pills proved unsuccessful. An attempt to place 20%; HCl acid induced up to 30 - 40 barrels per hour (BPH) dynamic losses at the shoe. Luckily, the losses healed relatively quickly, but the string remained stuck. After 29 hours of several unsuccessful attempts, a recipe of an enhanced combination pill of enzymes, and a weak acid accelerator was proposed, pumped across the stuck point, and allowed to soak. After a relatively shorter period of soaking, the string became free. The action of the enzyme/acid pill worked by destroying the polymer base of the filter cake created by the water-based drilling fluid. The homogeneous placement and action of the enzyme/weak acid pill across the stuck area ensured that it was more effective than the conventional HCL acid pill. Hence, the application is being presented as a potentially safe, efficient, and cost-effective option to free a differentially stuck BHA in water-based drilling fluid.

Success in freeing a stuck-pipe usually depends on two critical factors - an accurate diagnosis of the mode of stuck-pipe event (i.e. differentially or mechanically); and the ability to implement the remedial operations quickly, and effectively. By implementing the above described technique, significant non- productive time (NPT) was averted. The technique has since been implemented in subsequent differential stuck-pipe events in water-based drilling fluids with a 100%; success rate.
Performance Review of Chemical Sand Consolidation and Agglomeration for Maximum Potential as Downhole Sand Control: An Operator’s Experience
Authors: Hassan Nur Atiqah , Yeap Wei Jian , Singh Ratan , Nik Khansani Nik Zarina
Published: November 2020

Uncontrolled sand production has caused serious complication and monetary loss in oil and gas assets worldwide especially in mature fields. It is known to be drastically limiting the production rates and damaging downhole and surface equipment, inducing the risk of catastrophic failure. Sand production is commonly associated with contributing factors such as unconsolidated formation, initiation of water breakthrough and changes in rock stresses due to depleted reservoir pressure. To mitigate sand production, operators often opt for applying mechanical or chemical downhole sand control methods. This paper will discuss about the performance results and lessons learnt from the application of chemical treatment for downhole sand control over several mature fields in Malaysia.

Chemical sand consolidation (SCON) and sand agglomeration have been identified as effective chemical treatment to control sand production downhole. Both treatments involve injection of chemical into immediate near wellbore area of the reservoir with the aim to improve the strength of the incompetent formation and thus reducing the tendency for sand production. In most cases, SCON treatment consists of injecting fluid containing adhesive or resin for binding the sand grains while the main mechanism of sand agglomeration involves increasing the attraction between sand particles through processes such as polymer bridging interactions and charge neutralization. Stringent candidate screening and detailed pre-job planning are crucial in ensuring the success of both SCON and sand agglomeration treatment.

Over the past few decades, there were about 20 SCON treatment jobs and 3 sand agglomeration jobs were performed across several Malaysia fields with varying service providers and chemicals. The overall success rates for sand consolidation and sand agglomeration are 75% and 66% respectively. To evaluate the effectiveness of the chemical treatment for downhole sand control, analysis was conducted to study the effects of parameters such as completion type, perforation length, formation permeability, clay content, well preparation, formation temperature and placement methods.

This paper presents lesson leamt and best practice from several chemical SCON and sand agglomeration treatments performed over mature fields in Malaysia. Case studies for several wells will be examined to highlight the lesson learnt which are essential to further enhance the success of chemical SCON and agglomeration treatment. Best practice shall be incorporated into future campaigns to ensure chemical treatment as a successful means to control sand production downhole in a low-cost environment.
Source-Less Method Case Study: Integrated LWD NMR and LWD Azimuthal Resistivity Application in Low Resistivity and Low Contrast Reservoir in Bohai Bay
Authors: Zhu Meng , Cui Yunjiang , Xu Jinxiu , Chen Hongbing , Wang Ruihong , Wei Gang , Holger Thern , Zeng Xianlei , Liang Yi
Published: November 2020

The use of radioactive source porosity measurements is strictly prohibited in Bohai Bay, China. As an alternative, logging-while-drilling nuclear magnetic resonance (LWD-NMR) has been applied.

In one block of the Bohai Bay field, it is a big challenge to identify and quantify hydrocarbon reservoir sections due to little resistivity contrast between reservoirs and water zones. LWD-NMR technology and the azimuthal resistivity tool is able to solve this challenge. The low-gradient LWD-NMR tool not only measured porosity also provide T2 distributions, which can be used for fluid type characterization. The azimuthal resistivity tool has a deep azimuthal resistivity measurement that can identify nearby bed boundaries, up to 5 m from the borehole, while drilling. This information is available in real-time to the operator for decisions while drilling. The combination of the two measurements is capable of differentiating physical properties of the reservoir and providing information on fluid types. Thus, the operator can easily make decisions to optimize the wellbore placement and perform an accurate petrophysical evaluation of the reservoir.

A pilot hole and a horizontal hole are presented in this paper to show the advantages of LWD-NMR and the azimuthal resistivity respectively. In the pilot hole, the LWD-NMR has been used for fluid typing which can give a clear petrophysical interpretation of the reservoir fluids. Because in this low-resistivity contrast reservoir, it is difficult to differentiate oil zones (10+ Ohmm) and water zones (9- Ohmm) from resistivity data. The light oil, however, shows a much slower NMR T2 relaxation time than the water. Based on the identification of oil versus water by NMR in the pilot hole, three horizontal wells were successfully drilled in the oil zone. In one of them, LWD-NMR and azimuthal resistivity have been employed simultaneously for optimal wellbore placement by enabling to drill in the best part of the reservoir. The LWD-NMR measurements indicated reliably the presence of hydrocarbons and provided important reservoir properties. The azimuthal resistivity measurements identified the reservoir boundaries and the distance to them.

Under complex reservoir conditions as encountered in Bohai Bay, azimuthal resistivity and LWD NMR prove to be an accurate and robust source-less measurement combination. LWD NMR can effectively replace the traditional density-neutron source measurements for porosity. More importantly, the combination with azimuthal resistivity provides the operator with additional critical information for optimal wellbore placement and strengthening the confidence in petrophysical interpretation results.
A Novel Stimulation Design Approach Revives a Challenging Gas Field
Authors: Almulhim Abdulrahman , Hamid Saad , Khan Abdul Muqtadir , Hoong Chan Choon
Published: November 2020

Multiple attempts to commercially produce from a horizontal well in a challenging sandstone formation completed with the plug-and-perf method were rendered unsuccessful. An innovative stimulation strategy was proposed for the next candidate in an attempt to improve post-fracturing productivity. Three different types of proppant fracturing treatments were performed as a first-time application, including hybrid slickwater treatment, low-guar crosslinked treatment, and CO2 foam fracturing.

A hybrid design combining high-rate slickwater at the beginning and low-guar-loading crosslinked gel at the end of the treatment was pumped in two stages. This allowed minimizing the crosslinked fluid pumped while enhancing fracture half-length. Second, conventional low-guar fracturing was implemented in four stages. Crosslinked gel loading was reduced by 25% compared to gel that was utilized in offset wells. Finally, a CO2 foam fracturing design with a novel biopolymer linear fracturing fluid was implemented in the last stage. This reduced water consumption and improved the chance of increased gas production by yielding a higher-conductivity fracture network.

Friction pressure for CO2 foam was calibrated using bottomhole gauge data that was obtained with downhole gauges run prior to the calibration testing. The new calibrated friction numbers were then used for the bottomhole treating pressure calculation during the treatment. CO2 foam fracturing was found to be a significant success for this well based on multiple evaluation criteria. First, the use of foam helped conserve 1,000 bbl of freshwater compared to conventional stages. Second, the foam treatment allowed two times faster cleanup compared to other stages, based on cleanup time normalized over fluid volumes. Finally, production logging results showed that the foamed treatment achieved better production compared to other treatments in the well, considering productivity index (PI) normalized by the proppant mass, porosity, and zone mobility. The CO2 stage normalized PI was significantly higher than the other stages in the well. After the well was cleaned up, a production log was conducted, and it was analyzed to corroborate the higher production: 70% of the production contribution was seen from the CO2 treatment interval.

In most of the literature, estimates of the friction correlations for foams are based on empirical data. This paper gives the calculations of friction pressure based on field data. The combination of measured bottomhole data and post-cleanup production logging demonstrates the potential productivity improvements that can be achieved through novel design approaches. This type of data is rare in the industry and can help to improve the design of foamed fracturing treatments.