bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Lean Six Sigma Approach to Well Stimulation on Barrow Island, Australia
Authors: DI O'Reilly , BS Hopcroft , KA Nelligan , GK Ng , BH Goff , M Haghighi 
Published: October 2016

Abstract
Barrow Island (BWI), 56 km from the coast of Western Australia, is home to several mature reservoirs that have produced oil since 1965. The main reservoir is the Windalia sandstone, and it has been waterflooded since 1967, while all the other reservoirs are under primary depletion. Due to the maturity of the asset, it is economically critical to continue to maximise oil production rates from the 430 online, artificially lifted wells. It is not an easy task to rank well stimulation opportunities and streamline their execution. To this end, the BWI Subsurface Team applied Lean Six Sigma processes to identify opportunities, increase efficiency and reduce waste relating to well stimulation and well performance improvement.
The Lean Sigma methodology is a combination of "Lean Production" and "Six Sigma" these are methods used to minimise waste and reduce variability respectively. The methods are used globally in many industries, especially those involved in manufacturing. In this asset, we applied the processes specifically to well performance improvement through stimulation and other means. The team broadly focused on categorising opportunities in both production and injection wells and ranking them, specifically: descaling wells, matrix acidising, sucker rod optimisation, reperforating and proactive workovers. The process for performing each type of job was mapped and bottlenecks in each process isolated.
Upon entering "Control" phase, several opportunities had been identified and put in place. Substantial improvements were made to the procurement, logistics and storage of hydrochloric acid (HCl) and associated additives, enabling quicker execution of stimulation work. A new programme was also developed to stimulate wells that had recently failed and were already awaiting workover, which reduced costs. A database containing the stimulation opportunities available at each individual well assisted with this process. The project resulted in the stimulation of several wells in the asset with sizable oil rate increases in each.
This case study will extend the information available within the oil-industry literature regarding the application of Lean Sigma to producing assets. It will assist other Operators when evaluating well stimulation opportunities in their fields. Technical information will be shared regarding feasibility studies (laboratory compatibility work and well transient testing results) for acid stimulation and steps that can be taken to streamline the execution of such work. Some insights will also be shared regarding the most efficient manner to plan rig-work regarding stimulation workovers.
Enhancing Forecast Reliability Through Adoption of Integrated Production Modelling Technology
Authors: Muller Mathieu , Avent Matthew , Sie Will Da 
Published: October 2016

Abstract
Reliable reservoir and well performance predictions are essential to successful production, investment planning and capital stewardship for large liquefied natural gas (LNG) projects located offshore Western Australia. Successfully achieving this enables maximisation of revenues without eroding project net present value.
In order to make informed decisions about the timing of future gas supply for LNG plants, the values and trade-offs of different timings for future wells need to be assessed. To achieve this, excellent reservoir characterisation is desirable, as well as reliable modelling of the field management rules, production system and well constraints. This paper will discuss the improved modelling aspect of the field management rules, production system and well constraints that will be used as a basis for future investment timing decisions for the Wheatstone project.
Steps to improve the gas supply forecast included incorporating known production network constraints and downtime associated with well failure, in an effort to more accurately reflect production capability and operating envelopes. The adoption of a new software technology has supported the implementation of detailed and accurate field management logic into coupled production system – reservoir simulation models through a rule-based model controller. This enabled a more accurate representation of operational limitations, as well as more stable and reproducible simulation runs, modifiable well rate allocation schemes and well routing between production corridors.
Improving the simulation models with those functionalities required close integration with flow assurance and subsea engineers, as well as operations, which resulted in a better cross-functional understanding of how certain constraints can affect ultimate field recovery and future field development decisions. Enhancing the representation of the production profiles has also resulted in higher confidence in making more informed decisions for future drilling campaigns timing, scope and well locations.
Future model improvements will consist of incorporating revised operational constraints and updating the model's Field Management Controller as the production networks constraints and limitation are better characterised once the Project is in production phase. Evergreen updates of the reservoir models and the field management model are expected to be performed as new surveillance and production data become available, which will support an improved decision process for future gas supply investment.
Deepwater DST Designs, Operations and Analysis for the Exploration Well in the South China Sea
Authors: Yang Hongjun , Wu Muwang , Liang Hao , Liu Zhiqin 
Published: October 2016

Abstract
Deepwater exploration well test plays a decisive role in exploration of deep ocean field and establishment of development program. Considering the technical difficulties of deepwater test in Lingshui Depression of Qiongdongnan Basin, generation area of hydrate during testing progress and control method is studied, establishing testing working system based on critical testing flow and visual numerical well testing model to feasibly design build-up time. By optimizing the deepwater testing strings, testing program of one opening and one shut-in is presented and security and high efficiency of deepwater test is enhanced by means of modularization design of surface testing flow. The methods mentioned above are well applied to deepwater exploration well test in Lingshui Depression which indicates that the hydrate during testing progress and formation sand production are controlled effectively, the testing strings and modularization of surface flow can withstand the high capacity airflow, and integrated testing data is obtained, saving testing time and accomplishing reservoir evaluation.
The Use of Preservation Chemicals in Cladded Subsea Gas and Service Flowlines
Authors: Hali A. L. , Cook S. E. , Barber S. J. , Kearns P. 
Published: October 2016

Abstract
This paper presents some of the challenges and learnings associated with the application of preservation chemicals in a network of subsea Umbilicals, Risers, and Flowlines (URF) for a large-scale Liquefied Natural Gas (LNG) project in Australia. An overview of key considerations for chemical treat of water to meet the specifications necessary for long-term preservation of carbon steel and Stainless Steel (SS) cladded flowlines is also provided. Furthermore, the steps involved in formulating and qualifying a multi-purpose product to meet the requirements of the project are discussed.
In development of offshore gas fields the construction and commissioning of downstream infrastructure often extend beyond the time required to complete the installation of piping systems used in transporting gas and fluids to the processing centre. During the pre-commissioning phase, cleaning and pressure testing of production and service lines must be finalized to verify the structural integrity of the asset. The process is referred to as hydrostatic testing (or Hydrotesting) as water is typically used as the pipeline filling medium. The presence of water within the lines, following the completion of Hydrotesting procedures, can pose a serious corrosion risk due to the potential for growth of bacteria, deposition of sediments, and in certain systems the presence of dissolved oxygen in water. For these reasons, the use of preservation chemicals during Hydrotesting and subsequent preservation of pipework is critical to maintaining the integrity of the system. Preservation treatments typically consist of an active component for controlling Microbiologically Induced Corrosion (MIC), an oxygen scavenger to remove dissolved oxygen, and in some cases a corrosion inhibitor to supplement the treatment program.
The case history describes the best practices adopted in preservation of the above-mentioned URF system, located in an ecologically sensitive environment. In this project, the materials of construction of the flowlines demanded stringent specifications on the quality and treatment requirements for the Hydrotest water, to make it suitable for use in SS cladded flowlines. This condition, combined with the requirement for an environmentally-friendly chemical, drove the development of a ‘green’ preservation product cocktail with good corrosion inhibition performance and oxygen removal efficiency. Onsite sampling and chemical analysis procedures were also developed to ensure adequate and consistent application of the chemical during pipeline filling operations. The analysis allowed for accurate measurements of the product active components which, in turn, enabled the chemical treatment rate to be maintained within a narrow range.
It is anticipated that the newly developed product will be used in similar projects operating within environmentally sensitive locations where the use of a single, multi-functional chemical cocktail with a superior environmental profile is required.
Cost-Effective Parallel Reservoir Simulation on Shared Memory
Authors: Shuhong Wu , Baohua Wang , Qiaoyun Li , Xu Jinchao , Chensong Zhang , Chunsheng Feng 
Published: October 2016

Abstract
Reservoir simulation is an important tool for petroleum engineers to predict oil production and optimize the management of oil fields. Nowadays, large-scaled reservoir simulations are required by oil industry to simulate complex geological models in order to obtain high resolution results. When the reservoir engineers design new production processes, it is necessary to run dozens of simulations to find optimal solutions. The speed of serial reservoir simulators can be a big challenge. Parallel reservoir simulators with fast computational methods should be invested.
In this paper, we developed cost-effective parallel reservoir simulation techniques, which include mathematic fluid models, FIM discretization method, multilevel preconditioners and its implementations on shared memory. Based on the mathematical characteristics of the pressure and saturation in black-oil model, a multilevel preconditioner is set up which includes algebraic multigrid method (AMG), incomplete LU factorization, et al. The preconditioner is implemented on share memory to speed up the efficiency of numerical simulation. Several numerical experiments such as the benchmark test two-phase and three-phase SPE10 simulation and a field-scale mature waterflooding reservoir simulation were performed to test the efficiency, robustness of the proposed simulation technique and its parallel speedup.
In the numerical experiments, the proposed reservoir simulation techniques can successfully simulate numerical cases with different reservoir properties on a desktop computer. Numerical results show that the proposed reservoir simulation techniques are quite efficient in solving the nonlinear PDEs and robust for highly heterogeneous field-scale problems.
Gravel Packing Fluid for High-Temperature Wells
Authors: Prakash Chetan , Rama Mallikarjuna Shroff 
Published: October 2016

Abstract
An aqueous-based linear gel composition comprising diutan gum and an environmentally acceptable stabilizer has been developed for gravel packing applications. This aqueous-based gel works at elevated temperatures greater than 300°F. The rheological properties of these linear gels are particularly useful in gravel packing operations that involve shunt tubes. This paper presents laboratory studies that demonstrate the gel's thermal stability, rheological properties, minimal formation damage characteristics, and suitability for gravel packing operations.
Linear diutan gels exhibit excellent sand-suspension characteristics, even when they have relatively low viscosity, because of their hyper-branched structure. However, their use at temperatures greater than 270°F can be challenging because of limited thermal stability. A new fluid composition that comprises a biodegradable, environmentally acceptable gel stabilizer was developed to address this issue. Thermal stability and rheological properties were studied using a high-pressure/high-temperature (HP/HT) concentric cylinder viscometer at elevated temperatures and various shear rates between 5 and 1021 s−1. The sand-suspension characteristic was studied using a HP/HT autoclave. Formation damage characteristics caused by fluid invasion were studied by measuring regain permeability after coreflooding.
The results show the thermal stability of linear diutan gel improved from 270 to 310°F when the gel stabilizer was added. This fluid was stable up to 4 hours and exhibited excellent shear-rehealing properties at 310°F. The fluid rheology profile at various shear rates is in accordance with the criteria necessary for gravel packing operations that use shunt tubes. The fluid could suspend proppant/sand for 1 hour at 310°F with less than 20% settling. The gel stabilizer helped to improve thermal stability and sand-suspension characteristics by scavenging oxygen dissolved in the fluid and quenching the radicals generated at higher temperatures. The fluid was compatible with completion brine, crude oil, and oil-based drilling mud. Therefore, it could be used in nonaqueous fluid-pack completions. It showed more than 90% regain permeability, which suggests a clean break of gelling agent and low damage to the formation rock.
The good thermal stability and sand-suspension properties of the fluid system using the biodegradable, environmentally acceptable gel stabilizer makes it a good candidate for gravel packing operations in HP/HT reservoirs. The low-residue fluid property helps ensure economical production rates.
A Waterflood Induced Fracture Simulation Model for Naturally Fractured Low-Permeability Reservoirs
Authors: Zhang Feng , Wu Shuhong , Liu Huiying 
Published: October 2016

Abstract
Waterflood induced fractures are the new features affecting the reservoir heterogeneity in low-permeability reservoirs. Due to the high injection pressure, waterflood induced fractures will generate and propagate when the formation pressure exceeds fracturing pressure during the waterflood process of low-permeability reservoirs. Waterflood induced fractures will interact with natural fractures and create high permeable flow channels.
Conventional reservoir simulation models often fail in simulating the waterflooding of low-permeability reservoirs without considering the effect of reservoir pressure on the fractures. Current fracture models based on Perkins-Kern-Nordgren (PKN) model only focus on the simulation of the propagation of a single fracture without considering the interaction between waterflood induced fractures and pre-existing natural fractures. Therefore, based on the analysis of field data and the mechanism of waterflood induced fractures, a comprehensive wateflood induced fracture simulation model for naturally fractured low-permeability reservoirs is established.
Compared with the existing models, this waterflood induced fracture model can simulate the process of occurrence, propagation and closing of waterflood induced fractures due to the effect of high injection pressure and complex in-situ stress. The model considers the interaction between induced fractures and natural fractures, including slippage and crossing. The fracture model is coded in a module of a reservoir simulator. The simulation results shows that waterflood induced fractures worsen the reservoir heterogeneity, greatly increase the water cut of production well and lower the oil production rate.
The model can simulate the impact of waterflood induced fractures on waterflooding and optimize well patterns in low-permeability reservoirs to improve sweep efficiency and oil recovery.
What We Have Learned on Stimulating Intensely Naturally Fractured HPHT Deep Sandstone Comparing Acid-Fracturing, Fracturing and Non-Acid Stimulation
Authors: Che Mingguang , Wang Yonghui , Li Suzhen , Gao Rui , Wang Liao , Zou Guoqing , Liu Ju , Zhang Chengbin , Fan Runqiang 
Published: October 2016

Abstract
Recently, different stimulation techniques, including diverting acid fracturing, proppant fracturing and non-acid stimulation, were tested in Keshen 8 gas reservoir in Kuqa Gasfield of Tarim Oilfield. By comparing the production after stimulation, it is found that acid fracturing or non-acid stimulation techniques are more applicable for Keshen 8 gas reservoir. In this paper, these three stimulation techniques as well as their applications and results are presented.
Keshen 8 gas reservoir is buried in depth of 6700m–7400m with very intensely natural fractures, resulting in plenty of drilling mud loss and severe formation damage. Consequently, diverting acid fracturing was applied for damage removal and stimulation. Furthermore, non-acid stimulation technique and Schlumberger StimMORE* proppant fracturing technique were tested.
For the convenience of diverting acid fracturing and sand fracturing, casing cementing and cluster perforation completion was applied. In Keshen 8 gas reservoir, a total of 14 wells were stimulated, where the average mud loss was about 580m3, skin factor from well test interpretation was over 24, and testing permeability was over 5mD because of highly natural fractures, with homogeneous reservoir characteristics of log-log curve. After stimulation in these 14 wells, the average open flow capacity was 4.169 million m3. Among of which, 8 wells after diverting acid fracturing reached an average open flow capacity of 4.345 million m3, 2 wells after sand fracturing reached an average open flow capacity of 3.805 million m3 and 4 wells after non-acid stimulation reached an average open flow capacity of 4.358 million m3. These results show that, all stimulation techniques could achieve high production with little difference in wellhead production. During fracturing, slick water 272m3, fracturing fluid 1085m3 and proppant 52.5m3 were used in each well on average; during diverting acid fracturing, fracturing fluid 250m3, acid 175m3 and diverting agent about 100kg were used in each well on average; during non-acid stimulation, about fluid 400m3 was used in each well on average. In comparison, the cost of non-acid stimulation is about 50% of the cost of diverting acid fracturing and 25% of the cost of proppant fracturing. Therefore, stimulation with proper acid or non-acid fluid is economical and effective technique for Keshen 8 gas reservoir.
Obviously, our initial purpose is to obtain significant increase of production by use of progressive stimulation techniques. However, in terms of cost and production comparison, acid fracturing or non-acid stimulation techniques are more applicable for this kind of reservoir with very intensely natural fractures.
Production Logging Application in Fuling Shale Gas Play in China
Authors: Dejia Di , Wei Pang , Jun Mao , Shuang Ai , Ying He 
Published: October 2016

Abstract
Production logging play an important role on dynamic production monitoring and post-fracturing evaluation in shale gas horizontal wells, the technique can realize the rules of gas production and water flowback, in addition, understand the downhole dynamic production. However, the applications of production logging in shale gas play are not mature and still face many technical difficulties and challenges in China.
This paper proposed the technical roads and methods for production logging in shale gas well in Fuling oilfield based on the analysis of technical difficulties. At first, this paper discussed the optimization of downhole tools transmitted, the coiled tubing is more suitable than tractor for conveying the downhole tools, then analyzed how to determine the coiled tubing diameter, and provided coiled tubing mechanics simulation in a shale gas well. Secondly, we analyzed the selection of well control equipment, mainly focus on the optimization of pressure index of BOP. Thirdly, we analyzed the characteristics of array logging tools that produced by Schlumberger and Sondex, and illustrated the array tools have the potential risks that blocked and destroyed by debris of bridge plug, thereby the borehole cleaning is needed before testing. At last, we researched the calculation principle of flow rate with array tools and analyzed the data interpretation process according to the status of shale gas well and the principle of gas and water mix flow.
One case well in Fuling shale gas play shows that it is feasible to use coiled tubing conveyed array tools for production logging in shale gas well. The testing data interpretation results demonstrate the reliability of data interpretation method and the significance of production logging. For the case well, one half (6 stages out of 11 stages) fractures produce gas and the other half contribute nothing. The productive fractures also present different performance and the most predominant fracture contribute 36.47% of the total production. By production logging, not only fracture contribution to total production rate can be obtained, the flow regime and dynamic liquid level can also be determined. The production logging can be helpful for downhole fluid dynamic analysis and production optimization, and it may partly help the design of horizontal laterals and fractures scenarios.
Water Production Control Using Low-Salinity Water Injection
Authors: Zeinijahromi Abbas , Bedrikovetsky Pavel 
Published: October 2016

Abstract
A common problem in water flooding projects in heterogeneous reservoirs is early water production through high permeable zones. Polymer gel treatment has been used widely for water shut-off and well water-oil ration WOR reduction. However, a large injection volume is required for gel treatments that imposes high operational, material and environmental costs. This study introduces an alternative technique for water shut-off using Low-Salinity water injection. Injection of a small slug of Low-Salinity water induces permeability damage that blocks the water influx from high permeable water producing layers. The simulation study shows that the water shut-off treatment using Low-Salinity water, results in a significant reduction of produced WOR and may improve the final recovery. Injection of 10% PV of Low-Salinity water into the production well, resulted in ~20% reduction in produced WOR and ~6% incremental recovery.
Fluid Identification in the Low Contrast Oil Reservoir by Combining Array Dielectric Measurements and Nuclear Magnetic Resonance Data
Authors: Wang Jian , Shang Suogui , Wu Jinlong , Zhao Xianran , Yang Xingwang 
Published: October 2016

Abstract
Guantao oil reservoir of the Bohai Bay, is characterized by low formation water salinity, high pore structure heterogeneity and flooding, which complicates the logging response, especially the low contrast of resistivity response. Traditional methods by resistivity fail to estimate reservoir parameters accurately and cannot determine producible fluid type. In this study, the reservoir heterogeneity was investigated with advanced nuclear magnetic resonance data, and oil saturation was calculated using array dielectric data. Combining the two aspects, a special reservoir evaluation and fluid identification method was established.