bluuebunny/crossref_metadata_2025 huggingface dataset:
Improving the Conductivity of Natural Fracture Systems in Conjunction with Hydraulic Fracturing in Stress Sensitive Reservoirs
Authors: Keshavarz Alireza , Johnson Ray , Carageorgos Themis , Bedrikovetsky Pavel , Badalyan Alexander
Published: October 2016

The technology of injecting micro-sized proppant particles along with fracturing fluid is proposed to improve the conductivity of naturally fracture systems (e.g., cleats, natural fractures) in stress sensitive reservoirs, by placing graded particles in a larger, preserved stimulated reservoir volume around the induced hydraulical fracture. One of the main parameters determining the efficiency of the proposed technology is the concentration of placed proppant particles in the fracture systems. A laboratory study has been conducted to evaluate the effect of placed proppant concentration on coal permeability enhancement using a one-dimensional linear injection of micro-sized proppant into coal core and varying effective stress. Permeability values are measured for different concentrations of placed particles as a function of effective stress. The results show that there is an optimum concentration of placed particles for which the cleat system permeability reaches a maximum and permeability enhancement is more sensitive to concentration of placed proppant at higher than lower effective stress. The experimental results show maximum permeability enhancement of about 20% for an optimum concentration of placed particles at 490 psi effective stress. Permeability enhancement by 3.2 folds is observed at elevated effective stress of 950 psi. Finally, the paper proposes a field application strategy to apply graded particle injection in field case study.
Getting Safety Leadership Right
Authors: Fruhen Laura , Wang Lena , Griffin Mark , Finnerty Dannielle , Jorritsma Karina , Boeing Alexandra
Published: October 2016

Practitioner views on good safety leadership constitute implicit leadership theories. Themes in the descriptions of best practices in safety leadership, illustrate what behaviours are seen as most effective and may be most beneficial in leader development. Paricipants of this study (n=112) completed an online survey consisting of open questions regarding their views on safety leadership and multiple choice items concerned with how these behaviours may best be trained. Based on a model of safety leadership that contains four behaviours (Leveraging, Energising, Adapting, and Defending), the responses were analysed to identify themes. The analysis indicated that participants' responses particularly reflected three of the leadership behaviours namely Leveraging, Energising, and Defending. Adapting, which contains future oriented behaviours related to learning was not frequently indicated. Participants' responses also showed a preference for a blended approach for safety leadership training consisting of online and face to face learning. The results provide insights into the similarities and discrepancies between academics and practitioners' views on the conceptualization of safety leadership and can inform leader development.
Knowledge × Experience = Expertise
Authors: Selman Allison , Jas Eric , Harvey Chris , Wilson Ian
Published: October 2016

This paper presents the Offshore Pipeline Engineering Competency Project. The project was initiated by the Australian Pipeline Gas Association (APGA) in 2013, in response to the resource shortage of skilled offshore pipeline engineers. This project has resulted in a national framework and standard for competency in the field of offshore pipeline engineering.

The paper describes the Offshore Pipeline Engineering Competency Project from its inception through implementation with Engineers Australia for establishing a Special Area of Practice in Offshore Pipeline Engineering. The paper will describe the process used for competency development, the challenges and lessons learnt during the three year project; and the challenges that still lie ahead. The paper will detail the list of competency requirements and provide detail on the process of qualification through Engineers Australia. Finally, the paper will demonstrate how individuals and organisations can apply the competency framework for professional development.

This project demonstrates leadership and innovation within the Australian oil and gas industry. The positive response within Australia and internationally, indicates the importance of and demand for, this work. Success is attributed to the high level of collaboration within the industry. The first industry benchmark in offshore pipeline engineering has been set. This has many positive outcomes including guiding professional development, guiding educational institutions and ensuring the future of the industry is secure by developing the skills of the engineering workforce.

Establishing an Offshore Pipeline Engineering Competency framework is unique and the Australian industry is the first in the world to do this. There are ongoing discussions with international peak engineering bodies and standards organisations, to use this benchmark as the basis for a global framework. This will secure the future of the industry by ensuring that skilled resources are readily transferable between global regions.
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

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

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

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

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

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

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

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

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

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

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

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.
Evaluation of the Potential of Low Salinity Water Flooding in the High Temperature and High Salinity Dong-He-Tang Reservoir in the Tarim Oilfeild, China: Experimental and Reservoir Simulation Results
Authors: Liu Yongbing , Jiang Tongwen , Zhou Daiyu , Zhao Ji , Xie Quan , Saeedi Ali
Published: October 2016

This paper presents a systematic assessment of the potential of low salinity water flooding for the Dong-He-Tang reservoir in the Tarim Oilfield, China. This reservoir has a high reservoir temperature of 140 °C, high formation water salinity of 142,431 ppm total dissolved solids and an in-situ oil viscosity of 2.2 cp.

Our laboratory evaluation included contact angle tests, and spontaneous imbibition and core-flooding experiments using representative core samples from the reservoir. Contact angle tests were conducted at various temperatures (60, 100 and 140 °C) and pressures (20, 30, 40 and 50 MPa). Core-flooding experiments were conducted under the reservoir temperature of 140 °C. Formation brine and low salinity water (100 times diluted formation brine) were used in the experiments.

Contact angle and spontaneous imbibition experiments showed that low salinity water shifted the reservoir wettability towards more water-wet. In addition, spontaneous imbibition experiments showed that low salinity water recovered significantly more oil than high salinity water.

Furthermore, corefloods were conducted using low salinity water under tertiary and secondary modes. Experimental results were history matched to derive relative permeability curves and capillary pressure curves while considering the non-uniqueness of such history-matching. Results showed that compared to high salinity water flooding, low salinity water shifted relative permeability curves towards lower residual oil saturation, showing a higher oil relative permeability and lower water relative permeability at the same water saturation.

The parameters derived from laboratory experiments were used as input for reservoir simulation models to investigate the potential of low salinity water flooding in the reservoir using two layered box models. Findings showed that low salinity water accelerated oil production by increasing the oil relative permeability, thus resulting in a higher recovery factor with only a fraction of pore volume of low salinity water injection. Implications of these findings, such as slug size, salinity of injected brine, non-uniqueness of derived relative permeability curves on incremental oil recovery were assessed.

This paper is novel in the following aspects. First, the potential of low salinity water at a high reservoir temperature of 140 °C was systematically investigated. Second, laboratory experiments showed that low salinity water changed the reservoir wettability towards more water-wet, which is consistent with the observed shift in the relative permeability curves derived from core-scale numerical simulation. Third, the potential of the low salinity water in such high temperature environments was assessed using reservoir simulation based on the input from laboratory experiments.
A Unique Anti-Salt Polymer for EOR
Authors: Zhang Xiaoqin , Li Xia , Guo Songlin , Sun Gang , Guan Wenting
Published: October 2016

Daqing Oilfield is a heterogeneous sandstone oilfield with multiple layers. In order to protect the environment, produced water is widely recycled to prepare polymer solution, leading to great polymer consumption and poor economic effectiveness. For this reason, an exploratory research on anti-salt polymers is carried out. Polymer LH2500 is screened out and applied in pilot test in No.3 Block of Xingbei development zone, Enhanced recovery factor reached 10.3%, 45% polymer consumption was saved for ordinary polymers.

However, as produced water is recycled to prepare polymer solution, anti-salt polymer pilot test is urgently needed. To further enhance the recovery factor, anti-salt polymers of low concentration should have high viscosity in the high underground salinity.
Performance Culture Using Technical Limit Methodology: Learnings from Two Years of Deepwater Drilling
Authors: Crea F.. , Rabbitte T. P. , Lyons A.. , Chircop J..
Published: October 2016

This paper describes a two-year journey drilling deepwater exploration wells across three different countries, in challenging market conditions. The journey began in 2013 when the Transocean Deepwater Millennium was contracted by Woodside, in a 100 USD/bbl oil price environment, to drill deepwater exploration wells in Western Australia. The drilling campaign commenced in April 2014 with difficulties experienced through the first two wells. A recovery plan was initiated in late November 2014 that saw continuous improvement and top quartile performance achieved by the end of the campaign. These results were achieved despite the oil price falling below 35 USD/bbl and an unplanned transition to international waters in South Korea and Myanmar.

This paper focuses on the practical steps taken by the Woodside (Operator) and Transocean (Drilling Contractor) leadership team to influence workforce culture and recover from a slow start.

The recovery plan began with the alignment of Transocean's Management, Woodside's Management and the offshore leadership teams' vision and objectives. Technical Limit (TL) methodology was used to develop a set of performance indicators to monitor rig efficiency, establish clear and achievable targets for the off-shore crew, and to address the top five priorities for improvement.
Dynamic Production Targeting in Unconventional Gas Forecast Simulations Under Complex Economic and Facilities Constraints
Authors: Coman Chris , Mohiuddin Zeeshan
Published: October 2016

Unconventional gas fields can contain thousands of wells that may be located in geographically distinct areas, on a number of different authority to prospect (ATP) lease blocks. Wells flow to surface facilities that have varied fuel consumption rates and production constraints and which may also be located under different ATP leases to the wells. ATP leases may be wholly owned by the operator or production may be split with joint venture (JV) partnerships, under potentially complex production sharing contracts (PSC). Operators will have known gas contracts and predicted future gas demand that they must supply, but the full-field production rates required to meet these targets, following distributions, are unknown and variable.

This paper will present a methodology to dynamically control full-field production targets during simulation, such that the operator's predicted future gas demand can be reliably modeled, after fuel gas and JV equities are accounted for. The amount of excess production needed in each timestep is not fixed, and it changes dynamically based on many factors, such as block productivity, surface facility constraints, and the terms of the PSCs. This, and other complex behaviors can be captured and modeled within the solution, with relative ease.

The solution designed uses simulator keywords and user-defined quantities (UDQs) to account for all of these factors during forecast simulations of the model. Following implementation, the required full-field gas production target is dynamically calculated at each timestep, such that it meets the operator's gas demand, after removal of fuel gas and JV equity. This approach can significantly reduce the time taken to produce a valid production forecast, with production optimized to meet capacity limits in all cases and desensitized to subsurface and operational change. We describe in depth the rationale and technical details of the solution and provide an example case to demonstrate its implementation.
Top 10 Improvement Suggestions For Delivery Of Mega Projects
Authors: Alotaibi Mohammed Saad
Published: October 2016

With oil prices more than halved over the last year, the oil industry is gradually slipping into the red. Out of the 10 of the 20 European and North American oil and gas producers that have reported third-quarter results, seven have posted losses (Arab Times, 29 Oct 2015) with the remaining 3 reporting sharp drops in profits. Also oil producing countries are affected by the drop in oil price and several are reporting state budget deficits for 2015.

At current oil prices and oil price predictions, the challenge to find and deliver economically viable development opportunities (projects) is greater than ever.

Although many articles have been published on how to execute large projects, the industry still makes many unnecessary mistakes. Although estimates and statistics vary, general consensus is that the industry is still "losing" billions each year from poor project execution.

The article addresses the following topics; Poor Front End LoadingChanges during project executionNo or small Owner's teamProject is Schedule drivenInsufficient Operations input in (Toxic Facilities) DesignMega projects considered just bigger projectsRisk can be transferred to ContractorNo robust quality assurance planNo integrated teamsInsufficient stakeholder management
Optimising Upstream Separation Facilities by Retrofitting Existing Separators and Using Inline Separation
Authors: Westra R. W. , Barker R. A.
Published: October 2016

Existing operating facilities are often restricted by key bottle necks in the processing facilities that limit overall production. Typical bottlenecks limited capacities of separators and scrubbers that lead to liquid carry-over and in turn impact downstream compressors; water-in-oil emulsions leading to off-spec crude oil and too high oil-in-water content to meet discharge or re-injection specifications. By addressing and removing these bottle necks in a cost efficient matter the overall production and revenue of the crude oil production facility can be increased.

Especially in the current environment, any investment costs should be balanced by a quick return on investment to make good business case for investment. In this work a general retrofit strategy is presented, that consists of several steps, including problem analysis, bottleneck finding, different solutions strategies, and a selection phase. The focus is mainly focused on how to optimize separators and get the most out of existing production facilities.

A large focus of the production optimization methodology presented is on limiting the CAPEX requirement of proposed solution, in order to meet reduced budgets from oil operators in an industry suffering from declining crude oil prices. In order to achieve this different solution strategies are available and presented in this paper. Several case studies are presented in this paper, which clearly show benefits of the structured approach outlined. These cases shown how bottle necks are removed and overall production of a facility is increased.
Real-Time Interpretation of Leak Isolation with Degradable Diverter Using High Frequency Pressure Monitoring
Authors: Bogdan Andrey V. , Keilers Adam , Oussoltsev Dmitri , Lecerf Bruno
Published: October 2016

Degradable diverters are commonly used in multistage fracturing to increase the number of fractures along the wellbore and provide temporary isolation. Still, interpreting the effects of a diverter downhole remains challenging. In this paper, a nonintrusive monitoring technique is presented, which enables interpreting the effects of the diverter on multistage fracturing treatments.

This technique relies on the processing of pressure data acquired at high frequency. Unlike other monitoring techniques, its deployment is straightforward and relies only on surface acquisition and interpretation algorithms. It does not necessitate any change or additional steps in operations by utilizing events which are part of fracturing treatments. Data are interpreted on-site and in real time, and the results lead to an improved understanding about the performance of the diverter downhole, the evolutions of the wellbore connectivity with the formation, and the degradation process of the diverter.

The high-frequency pressure monitoring (HFPM) technique was used during several multistage fracturing operations. We present a case where the degradable diverter was used to effectively plug a leak during the fracturing treatment. The leak had inadvertently developed in a region of the well toward the heel, threatening the fracture stimulation stage aimed at the toe of the well. The HFPM technique was used to locate the leak, confirm its successful plugging with a degradable diverter, and monitor the degradation of the diverter. The HFPM provided control of the leak and data on when to pump additional diverter and the effects of the operation. The example demonstrates in a compelling manner that the HFPM technique enables real-time decisions that ultimately improve multistage fracturing treatments and operations relying on effective isolation and diversion.

The HFPM presented herein is a novel, nonintrusive method for monitoring multistage operations and enabling real-time decisions. The technique is particularly valuable for monitoring treatments that rely on diversion and zonal isolation. HFPM is enabled by state-of-the-art signal processing and interpretation algorithms. It has the potential to become a ubiquitous technique that is part of each and every multistage fracturing treatment.
Modelling of Drainage Capillary Pressure: Using the Modified Carman-Kozeny Purcell Model to Identify the Type of Pore Throat Distribution Inherent in Laboratory Data
Authors: Behrenbruch Peter , Do Huu Minh Triet , Bui Khang Duy , Hoang Tuan Gia
Published: October 2016

Capillary pressure relationships (drainage) involve key SCA parameters measured in the laboratory. Reservoir engineers use capillary pressure relationships in reservoir engineering calculations and dynamic reservoir simulation and petrophysicists use such relationships in saturation-height modelling. The objective of this paper is to describe a novel technique to identify pore throat or grain size distributions from capillary pressure profiles.

Capillary pressure, laboratory data are traditionally obtained from three different types of experiments: centrifuge, porous plate and mercury injection. The modified Carman-Kozeny Purcell (MCKP) model may be used in matching various laboratory results. Initial application of the MCKP model involved a standard matching procedure without differentiating according to the type of pore throat or grain size distribution. In this paper a refined, more powerful analysis technique is described in detail where matching of any laboratory data with the MCKP model is obtained in model space, showing various characteristics.

Characteristic profiles observed in model space can be directly attributed to the type of pore throat or grain size distribution: homogeneous (narrow), broad (poorer sorting) and bimodal (two distinct distributions), or a mixture of distribution types. Comparison of model generated profiles with laboratory curves indicate a high degree of congruence, typically R2 > 0.99, consistently better than any other capillary pressure formulation. The technique is also able to pick up artefacts, such as a sample fracture or laboratory procedural issues. It is shown how the MCKP model may be used in predicting capillary pressure relationships from basic parameters by building a framework based on end-point correlations derived from available laboratory data.

The paper presents various examples and a detailed case history for the Bayu-Undan gas field, covering various pore structure and diagenetic characteristics.
Reinstating Well Integrity in Severely Buckled Tubing
Authors: Mackie Colin , Bill Bjorn , Masson Graham , Kinch Elliot
Published: October 2016

Restoring well integrity with through-tubing intervention straddles is a relatively common activity. It is normally a lot less complex and less technically challenging than a more expensive well completion workover. However, a particular well in the North Sea was far from straightforward and presented a near impossible intervention challenge. The production tubing was severely buckled, which significantly reduced the effective tubing drift to depth and it was evident that the solution required extremely robust intervention equipment.

The well was completed as a primary sand column oil producer. The well experienced extensive corrosion and suffered from complex well integrity challenges. Initial attempts to restore well integrity were not successful, primarily due to the reduced tubing drift. Calliper interpretation software was used to identify the areas of significant corrosion within the tubing. Wellbore modelling revealed severely buckled tubing above the required straddle setting depth. The operator was forced to source a slim straddle design which was capable of passing through the tight restrictions.

The Anchored Production Straddle (APS) was the solution, with its small OD and relatively large ID. The APS was then customised to accommodate the depth and length parameters of damage within the well. The APS was successful in returning a challenging well to production and reinstating the production tubing integrity.

Due to the nature of the well, the robustness of the APS allowed for more than 150 downward jars through the tight restriction to deploy to depth. Despite the significant jarring, the APS was successfully set and the post-operation leak detection proved the straddle integrity.

The paper will look at the qualification tests done on the equipment, the execution of the operation, and the behaviour of the well before and after the intervention operations.