bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Filter-Cake Breaker Technology Maximizes Production Rates by Removing Near-Wellbore Damage Zone with Delay Mechanism Designed for High Temperature Reservoirs: Offshore Abu Dhabi
Authors: Nasrallah Mena , Vinci Matteo 
Published: October 2018

Abstract
This paper discusses the successful design, testing, and application of a new filter-cake breaker technology based on lactic acid chemistry. This technology provided prolonged delay in filter-cake breakthrough time at 220°F, which ensured coverage of the entire open hole, improved uniform filter-cake removal, minimized brine losses, and exceeded the expected production rates in different layers of the offshore Abu Dhabi reservoir.
Reservoir characterization was a fundamental component in the identification of the proper solution to maximize the return on investment of the assets. Temperature, permeability, porosity, and the nature of the reservoirs were studied thoroughly to determine one solution to be used in different reservoirs. Drilling fluid characterization (non-damaging with proper bridging package) and a proper filter-cake design were crucial to exceed the targeted production of the reservoirs. The paper discusses all steps from the laboratory testing of the breaker, application in different layers of the reservoir, and results obtained from the applications.
Lactic acid precursor was confirmed to be the "one fit solution" to cover the different reservoir layers. Because of its chemical structure, the hydrolysis process is slower than other breaker types currently available, which made it possible to maximize the breakthrough time at elevated temperatures, minimize completion fluid losses, and optimize the completion operations. Equally important, as an acid precursor rather than a live acid, this solution enabled the rig site personnel to implement the solution without affecting the health, safety, and environment (HSE) aspects that are fundamental in offshore locations. The possibility of pumping this solution through the rig pits enabled the jobs to be performed without additional equipment generally required for well stimulation. The achievement of these goals, supported by the higher production observed during the flow-back of the well, demonstrated how this solution maximized the return on investment for the assets located offshore Abu Dhabi.
The innovative use of lactic acid chemistry in the breaker, as compared to the conventional formic acid precursor breakers that are widely available, provided superior delay at higher bottomhole temperatures (in this case, 220°F) because of the slower acid liberation rate.
Behavior Analysis of a Wire Rope Replacing Sucker Rods with Finite Element Simulation
Authors: Fatemeh Fazeli Tehrani , Clemens Langbauer , Herbert Hofstätter 
Published: October 2018

Abstract
In this paper, a state-of-the-art wire rope is chosen for investigation regarding its applicability as a sucker rod string. Finite element simulation with Abaqus has been used for a detailed analysis of the rope's performance and possible failures along with its length.
The sucker rod string is a key component of sucker rod pumps, transferring the reciprocating movement of the surface polished rod to the downhole pump plunger. It is, however, exposed to severe cyclic loads, causing several complications from damaged rods and broken couplings to time-consuming workover procedures. Hence, continuous strings like wire ropes can be a convenient replacement for the conventional design. The mechanical properties of the introduced wire rope demonstrate high tensile strength and great resistance against creep and fatigue while its uniform design eliminates the chances of connection failure.
The proposed wire rope was designed to work in tandem with a sucker rod anti-buckling pump (SRABS) to facilitate its motion. The performance of this system was then simulated using a combination of MATLAB and Python codes, visualized in the interface of Abaqus. These simulations confirm that this wire rope can indeed replace the rod string in a sucker rod pumping unit. Detailed stress, load, and movement profiles were also compiled to allow for a comprehensive analysis. The results pointed out that pumping with a wire rope can be just as productive, or surpass the productivity of a system using conventional sucker rods. They indicate that the efficiency of this design highly depends on the geometry and depth of the well, type, and size of the pump, the compressibility of the produced fluid and string material elasticity. The optimization of the wire rope's performance could be achieved by using compatible Pumpjacks and proper downhole equipment, such as string protectors, all operating together under an optimum pumping speed.
This paper presents a noteworthy comparison between the performance of a conventional rod string and a wire rope at two reference wells. Laboratory and field tests are being planned to investigate the full capacity of the rope.
CO2 Tracer Application to Supplement Gas Lift Optimisation Effort in Offshore Field Sarawak
Authors: Abu Bakar Azfar Israa , Ali Jabris M Zul , Abd Rahman Hazrina , Abdullaev Bakhtiyor , Idris Khairul Nizam , Kamis Azman Ahmat , Yusop Zainuddin , Kok Jason Chin , Kamaludin Muhammad Faris , Zakaria Mohd Zulfadly , Saiful Mulok Nurul Nadia 
Published: October 2018

Abstract
Field B, located offshore Malaysia is heavily reliant on gas lift due to the high water cut behavior of the reservoir coupled with low-medium reservoir pressure. The field faces a challenge to efficiently execute production enhancement activities due to its low effective man-hour, a drawback of unmanned operation philosophy. The recent oil price downturn further exacerbates the limitation and calls for an innovative approach to continue the effort for maximizing oil recovery.
As majority of the producing wells are gas-lifted, Gas Lift Optimization (GLOP) is an integral part of Field B's routine production enhancement job. The previous practice of GLOP involves data acquisition process of surface parameters and wireline intervention to collect Bottomhole Pressure (BHP), mainly Flowing Gradient Survey (FGS). Relying on wireline intervention limits the number of gas lift troubleshooting activities due to the low man-hour availability. To address this constraint, CO2 Tracer application was implemented in a campaign to supplement Field B GLOP effort. CO2 Tracer is a technology whereby concentrated CO2 is injected into the gas lift stream via the casing. CO2 returns are collected at the tubing end and utilized to diagnose the gas lift performance.
The CO2 Tracer campaign was successfully executed in Platform A, B and C, covering 58 strings within an effective period of 3 months. This achievement is a milestone for the field as it opens a new approach in GLOP data acquisition process. Several advantages observed by executing this campaign is as follows: Multiplication of opportunities generation due to quick and simple operations of CO2 Tracer survey compared to wireline intervention for FGS.Reduction in HSE risks and intervention-related well downtime due to minimal intrusive requirement for well hook-up.Better understanding of complex dual gas lift completion due to simultaneous survey execution.Supplement CO2 baseline measurement for flow assurance monitoring.Quick quality check on gas lift measurement device.
This paper will discuss on the challenges at Field B to implement GLOP, technology overview of CO2 tracer, the full cycle process of the CO2 tracer campaign and results of the campaign. Several examples of the findings will also be shared.
Leveraging Data Analytics to Optimise Production Performance
Authors: Copping Simon , Payne Jason , O'Malley Ronan 
Published: October 2018

Abstract
The current downturn in the industry has increased focus on production optimisation and cost efficiency. Organisations are now recognising opportunities to exploit and leverage data analytics to help deliver such improvements.
The paper describes how machine learning techniques have been successfully applied to improve production and processing performance.
It introduces a number of keys concepts relating to artificial intelligence and identifies the challenges of traditional data analysis techniques. The paper outlines a methodology in defining and evaluating suitable use cases for the application of machine learning and details both an upstream and downstream example of where the methodology has been successfully applied to optimise performance.
The first example presents how an operator transformed work practices to accurately predict valve actuator failures from anywhere between 12-18 months before the actual event using operational expertise, digitalisation and machine learning techniques.
Another example describes a natural gas transportation and processing system that transports gas from several offshore terminals to an onshore reception and processing terminal. Machine learning models were successfully developed to predict NGL Reid vapour pressure (RVP) at the processing terminal using historical (gas composition, process operating and RVP) data. RVP is a common measure of volatility as determined by the test method ASTM-D-323. The predictor model is valuable as it allows proactive export route management from the terminal, minimises potential interruption of production due to off-spec NGL and allows mitigation actions to be identified and implemented if high RVP is predicted to be likely.
Innovative All-Electric Tubing Retrievable Downhole Safety Valve
Authors: Scott Bruce , Chakkungal Joseph Joseph , Penman Ian 
Published: October 2018

Abstract
In the search for energy, new technologies bring added benefits. These new technologies are driven by the need to be more environmentally conscious, reduce costs, increase reliability, reach farther and deeper, and provide more and better data to more effectively manage wells and equipment. With these new technologies, the industry is making a steady transition toward electrification and digitalization of the well completion. Electrification of completion equipment has occurred at a steady pace for several years, but the pace has quickened as the reliability of equipment has improved and the benefits of additional data have been realized. Within the last few years, the first completions with all-electric Christmas trees (XT) were run. Because all-electric tubing retrievable downhole safety valves were not yet available, these were not true all-electric completions. These first wells required the XTs to be installed with hydraulically operated downhole safety valves, making these mixed-technology completions. Recently, an all-electric tubing retrievable downhole safety valve was developed, qualified, and field tested. The introduction of the all-electric tubing retrievable downhole safety valve will bring the benefits of an all-electric completion to the oil industry.
All-electric tubing retrievable downhole safety valves, also known as electric surface-controlled subsurface safety valves (ESCSSV), build upon field proven technology, but offer the added benefits that an electrically operated tool can provide while performing the same critical function as the traditional hydraulic downhole safety valve.
This paper describes the development and deployment of the ESCSSV; it includes discussions about the qualification program of the valve and valve systems, integration with the all-electric subsea XT and control system, and installation in the well.
Reliable Carbonate Stimulation Using Distributed Temperature Sensing Diagnostics and Real-Time Fiber-Optic Coiled Tubing Intervention in Kuwait
Authors: Santin Y. , Matar K. , Montes E. , Gorgi S. , Joya J. , Bu-Mijdad M. , Al-Mubarak H. , Al-Lafi M. , Al-Hamad A. , Al-Askar H. , Al-Shamaa M. , Al-Enizi O. , Bu-Qurais A. , Madhavan S. , Al-Dashti M. 
Published: October 2018

Abstract
Injection profile enhancement has been one of the primary objectives for an operator in Kuwait. Stimulation interventions in injector wells directly affect the enhancement of oil recovery in producer wells. This paper presents the application of a verifiable stimulation intervention in a water injector well to help achieve the operator's objectives.
The intervention presented several challenges. There was limited information available for the newly drilled carbonate formation under consideration in the Greater Burgan Field. Additionally, the fiberglass well tubing required significant attention before running in hole (RIH) with coiled tubing (CT). A high concentration of H2S was identified in Formation A; therefore, gas returns were also a potential issue. This paper discusses the methods used to help address these challenges. During this case study, real-time fiber-optic cable CT (RTFOCT) technology was applied in the fiberglass tubing injector well to determine initial well injection profile and adjust treatment accordingly. This technology includes a fiber-optic cable integrated into the CT pipe and a modular sensing bottomhole assembly (BHA).
RTFOCT technology allows for rigless operations and performs interval diagnostics, stimulation treatment, and evaluation in a single CT run. During this case study, the well injectivity increased by more than 100%. Diagnostics and evaluation were performed by analyzing the well thermal profile using fiber-optic distributed temperature sensing (DTS). The BHA helped ensure accurate fluid placement during the treatment using real-time pressure, temperature, and depth-correlation sensors. The RTFOCT technology provided real-time downhole information that was used to analyze reservoir parameters, help ensure accurate fluid placement, and enable quick and smart decisions regarding the stimulation treatment stages based on the fluid intake in different zones. During injection, the heterogeneous fluid flow became homogeneous along the interval confirmed with the thermal-hydraulic model (THM). This helped reliably complete the intervention operations and delay possible water breakthrough in the producer wells and extended reservoir recovery.
Pushing the Thermal Stability Limits of Hydraulic Fracturing Fluids
Authors: Almubarak Tariq , Li Leiming , Nasr-El-Din Hisham , Ng Jun Hong , Sokhanvarian Khatere , Alkhaldi Mohammed , Almubarak Sama 
Published: October 2018

Abstract
In order to satisfy the demand for oil and gas, it becomes increasingly necessary to produce from formations that are deeper, have low permeability, and higher temperature. Conventionally, hydraulic fracturing fluids make use of viscosifiers such as guar and its derivatives to generate the rheological properties required during the fracturing process. However, to withstand the high-temperature environments, higher loadings of polymer is required. This leads to an increase in polymer and additive concentrations. Most importantly, these higher loading fluids do not break completely, and generate residual polymer fragments that can plug the formation and reduce fracture conductivity significantly.
This work builds on previous work which introduced a new hybrid dual polymer hydraulic fracturing fluid that was developed for high-temperature applications. The fluid consists of a guar derivative and a polyacrylamide-based synthetic polymer. Compared to conventional fracturing fluids, this new system is easily hydrated, requires less additives, can be mixed on the fly, and is capable of maintaining excellent rheological performance at low polymer loadings. In this work, the fluid is further optimized to withstand even higher temperatures up to 400°F.
Total polymer loadings of 30 lb/1,000 gal and 40 lb/1,000 gal dual polymer fracturing fluid were tested in this work and were prepared in the ratio of 1:1 and 1:2 (CMHPG: Synthetic). They were then crosslinked with a metallic crosslinker and placed in a HPHT rheometer to measure the viscosity between 200 and 400°F. After observing the failure temperature of the mixtures, additives such as buffers, crosslinking delayers, and oxygen scavengers were added and tested at temperatures above that point. The type of crosslinker used was also varied to observe the effects of the rate of release of the metallic crosslinker on thermal stability.
The results indicate that the 1:2 (CMHPG: Synthetic) mixture performed better at temperatures exceeding 330°F than the 1:1 mixture. The failure point of both mixtures was observed to be 350°F for the latter while the former failed at 370°F. The addition of a crosslinker that allowed a more controllable release was observed to improve the thermal stability of the fluid mixture above 370°F by increasing the polymer's shear tolerance. The addition of additives to the mixture was shown to improve the thermal stability of the solution to varying degrees. Of the three additives, the most significant enhancement came from the addition of oxygen scavengers while the least was from the buffer solution.
Geomechanics: A Key to Understanding the Underperformance of Fracture Treatments
Authors: Rahman Khalil 
Published: October 2018

Abstract
In many cases, the production prediction at the fracture design stage and later from the post-fracture pressure-matching exercise is never realized. The underperformance of fracture treatments is often attributed either to formation damage, proppant crushing and embedment, or to the poor reservoir quality despite a reasonably good reservoir property indicator from all sources including the pressure decline in a mini-fracture test. Based on several case studies, this paper highlights a number of issues that were found responsible for underperformance of fracture treatments. The understanding and mitigation of these issues require the application of comprehensive geomechanics.
For each case, a comprehensive geomechanical model was built for the field, characterizing the depth profiles of all three stresses, rock mechanical properties and the direction of the horizontal stresses by integrating available data from various sources including drilling and logging data, laboratory rock test data and mini-fracture test data. The contrasts in stress and rock mechanical properties among various lithologies along the well path were created based on fundamental geomechanical principles. The hydraulic fracture growth was simulated as per the pressure-matching practice for each treatment carried out. The production condition was applied to the simulated propped fracture to predict the production and compare it with the actual production data where available.
Issues that were found responsible for lower-than-expected production include (1) out-of-zone fracture growth that could not be predicted using the oversimplified geomechanics; (2) poor connection between wellbores and fractures for unfavorably oriented wells; (3) non-optimum perforation intervals that caused non-optimum fracture growth and near-perforation low conductivity; (4) malpractices in treatment execution that resulted in disconnected fractures with the perforations; and (5) suboptimal treatments for reservoir conditions. Appropriate mitigation strategies were recommended for wells in production, and increased productions were reported where the recommendations were implemented. One significant observation is that several oversimplified techniques currently used in the industry create significantly different stress contrast profiles than that was found based on fundamental physics of geomechanics, though all these profiles could be calibrated with the same closure pressure from a mini-fracture test. The use of such inaccurate stress contrast profiles is primarily responsible for unrealistic fracture and production predictions.
Ceramic Sand Screens: Qualification Strategy for a High Rate Gas Application
Authors: Cadogan Paul , Hall Steve , Jackson Richard , Meschke Frank , Read Trent , Gundemoni Bhargava , Barth Peter 
Published: October 2018

Abstract
As part of the overall Ichthys project there was a requirement to develop a remedial sand control application that would be suitable for installation should the sand production levels exceed the tolerance of the system. After an exhaustive review of available techniques, a remedial insert ceramic sand screen was selected as a potential option for these high rate gas wells. In order to be confident that the screen would be suitable for the application a comprehensive design and qualification plan was developed.
Due to the nature of the application and the technology itself the qualification programme was significantly more complex than typical oilfield equipment qualification; many of which can adopt standard API/ISO testing protocols with clear cut pass/fail criteria.
A number of specific elements were required to underpin the qualification. Firstly and perhaps most importantly was pre-qualification of the overall strategy itself. This can be thought of as the engineering work to endorse the approach, including the assessment of any inherent risks, and the development of the overarching qualification framework including understanding the dependencies between specific qualification work scopes.
Once the strategy was endorsed and the framework developed, a significant amount of time was spent maturing the testing programme and the subsequent pass/fail criteria, often involving extensive discussion with a number of specialised companies and especially the provider of the screen.
A thorough and extensive set of modelling and testing was conducted to endorse the final product for the application including fundamental FEA and CFD modelling through more traditional burst/collapse testing, end ring weld certification and corrosion studies to bespoke bending, impact and erosion testing.
In addition as this is a new technology and does not conform to any existing sand screen quality plan it was necessary to conduct a joint quality management system audit and screen manufacturing assessment. This led to the construction of an agreed Quality Control Plan; and specific production quality checks to ensure critical requirement conformance of the overall process and end product. The end result was a successfully qualified product for the Ichthys high rate gas remedial application.
Underbalanced Jetting in CSG play
Authors: Vatan Mike , Desplat Melanie , Giambalvo Anthony , Amorer Gabriel 
Published: October 2018

Abstract
Historically, openhole barefoot completions used in conjunction with cavitation and surging or underreaming techniques, have proven to be an effective way to stimulate coal seam gas wells to increase effective permeability. (Logan et al, 1989). However, despite having a positive impact on production, the unpredictable time required to cavitate and surge the wells can be substantial, sometimes requiring up to 4 weeks to execute required scope. This time consuming technique leaves the operator vulnerable, working in an unstable borehole where fishing operations are common and the outcome of delivering scope is not guaranteed. The main challenges of accurately predicting cost to keep the projects economical, continuing to produce coal fines during cavitating and surging, and continual sloughing are some major drawbacks.
The other alternative on the market is underreaming, which has its own limitation in relation to the maximum possible enlargement of the borehole or more specifically, the size of the underreamer that can be utilized. Faced with these limitations, there was a significant need for an innovative way to stimulate wells to increase production while minimizing costs.
This paper introduces the ingenious use of a newly designed jetting tool, with specialized nozzles, to enlarge a borehole size using a combination of air and mist. This case study conducts a lookback on design parameters, cost, and safety improvements introduced by this new technology.