bluuebunny/crossref_metadata_2025_split huggingface dataset:
Montney Unconventional Gas Play: Managing Choke Wear Using Flow Coefficient Diagnostics
Authors: Grant Lee 
Published: October 2015

Abstract
The objective of this project was to improve wellsite safety, optimize choke life, and reduce downtime in highly erosive Dawson Montney (British Columbia, Canada) gas wells through use of real-time flow coefficient (Cv) diagnostics. This was achieved by developing a methodology to trend well behaviour, characterize wear patterns and create Wear Reports based on user defined set-points.
A 2-phase flow coefficient equation was used to reduce error in higher liquid-gas-ratio wells and to improve universality. Percent Cv deviation (%Dev) is introduced and calculated in relation to the theoretical choke curves and acts as a key wear indicator. A custom Steady-State Slope-Fitting algorithm and workflow was developed to numerically characterize choke behavior. Using well specific slope durations based on flow behavior as well as elimination of statistical outliers, reliable slopes can be calculated. Logical statements comparing the slopes of key parameters to user adjustable setpoints identify wear patterns and create a shortlisted "Wear Report". These wells can be quickly validated using a custom Spotfire based visualization template.
A subset of the Dawson Montney Field (107 wells) was originally piloted to validate methodology. Two generalized wear signatures (for auto and manual choke control) were theorized and vetted using a combination of wear trends and failure analyses which showed high internal wear. By comparing slopes of flow rate, choke position, and %Dev to set-point values, wear signatures can be identified. Workflow was easily adapted to be effective with the Dawson Montney standard choke type as well as a new choke pilot. Many wells have exhibited wear signatures and have been correctly identified by the software, thus increasing safety between scheduled onsite choke condition checks. Early indicators have been communicated to field personnel and well specific plans have been made to replace chokes. In many cases, early detection has allowed pre-planning of onsite work to minimize well downtime (from 24–48 hours downtime to 4 hours or less) and maximize cash flow generation ($10–20k accelerated, using typical rates and netbacks). This program has now expanded to over 400 Montney wells and will be monitored by a continuously manned Operation Control Center.
Use of a slope fitting algorithm to numerically describe flow/wear behavior, creation of prelim wear set points/limits, and the wear signature identification logic is a novel approach to detecting and mitigating issues related to choke wear, which ultimately improves safety and reduces costs.
Seismic Methodologies Adapted For Use In Acoustic Logging
Authors: Biswas Partha , Ley Shreya B. 
Published: October 2015

Abstract
If we are to continue to use acoustic logging as a viable method for characterizing wellbore formation characteristics, such as natural fractures, then logging techniques developed for conventional reservoirs and vertical wells should be updated and adapted for use in today's unconventional and directional drilling applications. Unlike seismic processes, which have undergone research and changes to adapt to the more complex characterization needs of today's wells, acoustic logging techniques have stayed relatively stagnant. In order to stay relevant, acoustic logging processes must adapt for use in unconventionals as well. The following discussion focuses on four seismic techniques adapted for acoustic logging processes, the process for choosing these particular techniques to adapt, and the results achieved.
We have based new acoustic logging algorithms and routines on these four seismic techniques and adapted the research into proprietary software for processing raw, acoustic waveform data. First, we have adapted the use of compressional waves to map drops in energy across natural fractures which allows industry to move away from many of the limitations imposed by more widely used techniques. Second, as part of the workflow presented in the compressional fracture identification methodology, we have adapted stacking to improve results and amplify anomalies. Third, in order to provide a broad available toolsets and usable data, we have incorporated advanced filtering routines based on predictive deconvolution, which can be used to process acoustic data from alternative tools or to enhance data collected using measurement-while-drilling or logging-while-drilling tools. Fourth and last, applicable to both shear and compressional waveform processing, we have chosen to move away from Alford-based azimuth computations, or at least correct for assumptions in Alford-based azimuth computations that are not relevant in unconventionals, so that borehole deviation does not adversely affect the processing.
The use of compressional waves to map natural fracture patterns has found great success in both vertical and lateral wells and has been used in the field in the Permian, Eagle Ford, the Bakken, and in various international fields. Comparisons against image and core results demonstrate an 80-85% correlation rate. The following discussion will go over two case studies, the evaluation method used to study the correlation, briefly discuss the workflow used, and also provide an example of how the advanced filtering produces much cleaner waveforms for processing than relying solely on frequency filtered waveforms.
These new processes allow acoustic processing to enter the modern age of exploration and create a new, more direct process for finding the fracture density in the well bore. Furthermore, they may be incorporated in to new and old processing techniques, making the most of the modern tools available.
Low Resistivity Oil Sands: CO and PLT Logs Find By-passed Oil and Extend Life of Mature wells
Authors: Faizal Ardi W , Handoyo Tri , Panca Suci W , Pramudhita Bayu Adhi , Jafet Jafet , Mudayana Riko 
Published: October 2015

Abstract
This is a case history of how aggressive well surveillance can increase oil recovery and dramatically extend well life.
MSBK is a 20 MMSTB OOIP field in the Malacca Stait PSC, located on Padang Island, Riau Province, Sumatra (Figure-1). Oil has been drained from the Lower Sihapas G-3010 sand in two development wells: MSBK-1 for 22 years, and MSBK-2 for 13 years. Other sands were penetrated, but had low-resistivity or 2-3 ohm.m, which was similar to water sands and shale. Given this lack of resistivity contrast, these sands were not considered further.
By 2011, oil production had declined and was approaching the economic limit. Facing the prospect of abandoning the wells, the team looked at ways to extend well life. Although the resistivity logs were not promising, oil shows were noted in the G-1010 and G-1020 sands in MSBK-2, with other oil shows in the G-1010, G-1015 and upper G-3010 sands in MSBK-1.
This paper will elaborate the workflow used to find potential by-passed oil, covering wireline and mud logs, through-tubing perforation (TTP), surveillance logs and finally the workovers.
The team successfully found and developed the by-passed oil.
MSBK-2 had an oil gain of 150 Bopd, and the workover paid off in 12 days. MSBK-1 had oil gain 135 Bopd, and the workover paid off in 27 days.
Locating the Remaining Oil (LTRO) in a Mature Field in the Tertiary Baram Delta, Malaysia
Authors: Kittrell Charles , Sessarego Horacio , Tewari Raj Deo , Othman Tg Rasidi , Yeomans Hugh G. , Taslim Gunawan , Djohor Mohamed , Bahraie Ramin , Meyer Juergen , Jiang Long , Whitney Patricio , Enriquez Hugo A. , Kiome Patrick , Montero Alfonso R. 
Published: October 2015

Abstract
The Late Neogene Baram Delta province developed on an active margin located offshore Borneo in Malaysia. The field has been in production since 1982, and a total of 64 wells have been drilled from three (3) platforms. This paper discusses the process used to locate remaining oil for infill drilling. This involved a multidisciplinary effort including geology and geophysics, reservoir engineering, drilling / completion, and production technology.
The geologic and geophysical (G&G) assessment consisted of updating the static model and constructing mobile oil thickness and structural and bubble maps of all reservoirs. These maps were used in conjunction with original and current fluid contacts and helped to identify and locate remaining oil accumulations. The target portfolio was screened and ranked, and preliminary wellbore paths were built. Four (4) new wells and eight (8) sidetracks combining either shallow or deep targets were passed on to the reservoir engineering team for optimisation from simulation models and first-pass estimation of oil incremental reserves.
Reservoir simulation focuses on optimising target intervals as determined through G&G work and drilling design. Well constraints are set to be consistent with operating field production practices and facilities constraints. Completion intervals for the dual-string wells are optimized to minimise water cut and maximise oil rates. All simulation results are rigorously checked against offset well production and observed properties.
Once drilling targets are risk-assessed on the basis of structural, fluid contacts, and properties uncertainties, the final well trajectories are designed by the drilling team.
This study identified and ranked multiple undrained and appraisal areas. A full infill redevelopment consisting of more than 10 accelerated wells planned through the utilisation of existing facilities was presented and approved by PETRONAS Carigali Sdn. Bhd. (PCSB). The well and target portfolio is focused on three (3) main field development areas: Attic oil in shallow Pliocene reservoirsNew development areas in deeper Miocene levels on the southern blockUntapped deep Miocene reservoirs on the northeastern flank in crestal location
The first two (2) sidetracks and three (3) workovers were successfully completed in December 2012, and the current oil production is 40% higher than originally estimated. The successes to date have proved the effectiveness of the concepts that were applied to identify and develop the remaining oil, and the field became East Malaysia's top producer.
Electrical Submersible Pumping Systems vs. Long Stroke Pumping Units: A Case Study of Economical Comparison in a Low-Volume Well
Authors: Proaño Alejandro , Gomez Cesar , Molotkov Roman , Villacis Nelly , Sola Ana , Suarez Simon 
Published: October 2015

Abstract
Historically, the electric-submersible-pump (ESP) system has been the most cost-effective artificial-lift technology to draw down deep wells with flow rates of more than 200 STB/D. In lower-rate wells, other technologies such as rod pump systems have proven to be more cost effective. However, in recent years the long-stroke pumping unit has extended the rod-lift operating envelope to the point that rod lift now provides competitively effective pumping in wells traditionally using ESPs.
The case study within this paper focuses on a mature well located in a Petrobell's field in South America, Cachiyacu 1, in which a production decline rendered the existing ESP system oversized for the well conditions. The operator was seeking a more efficient lift solution before ESP failure due to down-thrust operation. A comparison of energy consumption, efficiencies, and operating expenses (OPEX) was used to evaluate the two artificial-lift options—a smaller ESP system or a long-stroke pumping unit.
This study compares the costs of power and workovers between an ESP and a long-stroke pumping unit. It shows that over a well-documented period of time, the long-stroke pumping unit reduces power consumption by providing greater operational efficiency than ESPs at similar depths and rates. The long-stoke pumping unit also reduces workover costs with less expensive downhole components.
This operator realized significant financial savings and reduced energy usage by choosing the long-stroke pumping unit. Although both the ESP system and the long-stroke pumping unit can deliver similar production rates, in this case, the long-stroke pumping unit was able to provide a higher production rate than the ESP. The LSPU also provided a more cost effective option in this application (CAPEX & OPEX).
A Parallel Framework for Reservoir Simulators on Distributed-memory Supercomputers
Authors: Liu Hui , Wang Kun , Chen Zhangxin , Jordan Kirk E. , Luo Jia , Deng Hui 
Published: October 2015

AbstractThis paper presents our work on developing a platform for high performance reservoir simulations, which is developed to support the implementation of various reservoir simulators on distributed-memory parallel systems. This platform employs MPI (Message Passing Interface) for communications and OpenMP for shared-memory computation. It provides structured grids due to its simplicity and cell-centered data for each grid cell. The platform has a distributed matrix and vector module and a map module. The map connects the grid and linear system modules. Commonly-used Krylov subspace linear solvers are implemented, including the restarted GMRES method and the BiCGSTAB method. It also has an interface to a parallel algebraic multigrid solver, BoomerAMG from HYPRE. Parallel general-purpose preconditioners and special preconditioners for reservoir simulations are also developed. The numerical experiments show that our platform has excellent scalability and it can simulate giant models with hundreds of millions of grid cells using thousands of CPU cores.
Next Generation Damage Resistant Liquid Coatingsa
Authors: Devadass Melvin , Yousif Aneece 
Published: October 2015

Abstract
The selection of a reliable pipeline coating is an integral part of repair and rehabilitation of aging pipelines. Liquid epoxies have been a preferred choice, specifically considering handling properties, application, compatability to cathodic protection (CP), corrosion control and soil stress. The next generation of field applied two part liquid epoxy coatings will need to offer application and performance properties beyond the specification requirements set forth by the industry. These liquid coatings are designed to protect steel from the harsh effects of corrosion both onshore aswell as in offshore environments. While high build epoxies are generally well regarded for adhesion, one challenge has been to match performance with higher coating flexibility.
This paper introduces the next generation two part liquid epoxy coating with superior flexibility, greater surface tolerance and improved functional properties to meet the demands of rugged terrains supported by laboratory and field data.
Industry specifications have not offered much guidelines on two part liquid epoxy coatings and not much advancement in technology has come to the industry. Abrasion Resistant Epoxy Coatings (AREC) are the next generation of field applied pipe line coatings. They provide a tough coating with outstanding mechanical properties like abrasion resistance, gouge resisastance and impact resistance while maintaining a high degree of flexibility. This next generation two part liquid epoxy coatings will provide similar flexibility properties as FBE, but with the ease of application that two part liquid epoxies offer.
Innovative Offshore Stimulation Campaign
Authors: Sukkar Luai , Arukhe James , Yateem Karam , Ajmi Saleh , Danish Syed Muhammed , Becerra Etan 
Published: October 2015

Abstract
This paper highlights the challenges and limitations encountered, and the respective solutions executed, during an acid stimulation campaign, conducted on multiple offshore power water injector (PWI) and oil producers (OP).
The field development concept for the field in includes a water drive mechanism, having unique placement of both onshore and offshore peripheral water injector wells. This field has a major concentration of extended reach hydrocarbon wells in the region.
Normally, post-drilling or post-workover operations, acid stimulation is foreseen to assure attainment of desirable well productivity or injectivity potentially that might be affected by drilling mud. For optimum treatment, each well requires uniform acid stimulation with significant volumes of chemically inhibited and diverted acid to achieve uniform zonal coverage, which are placed through Coiled Tubing (CT). Based on multiple laboratory tests conducted, an optimized treatment gradient (gal/ft) was fixed.
A rigless intervention technique was used, with a stimulation vessel handling the chemical additives, acid, diesel, and water logistics, on-the-fly treatment fluid mixing, and pumping, while a self-propelled barge handled the CT unit with nitrogen lift pumping capability and return handling system.
The successful combination of the CT intervention and stimulation vessel fluid handling system in this campaign resulted in improvement post-stimulation in terms of both injectivity and productivity. This paper includes general technique and volumes used to successfully stimulate wells.
The Properties Analysis for Reservoir of Sand and Mud Thin Alternations in San Jorge Basin
Authors: Hai Qu , Baoping Lu , Tingxue Jiang , Xinrun Lv , Guien Li , Xingchuan Li 
Published: October 2015

Abstract
The multi-layered stratigraphic formation is the main property in the San Jorge Basin. Because of thin interbeded sand-mudstone, these formation exhibit major inconsistencies and anomalous results in formation water salinity. In addition, the complex reservoir characteristics lead a great challenge to fracturing in that it is no easy to control fracture height. Thus it required the use of optimum hydraulic fracture to improve the hydrocarbon production.
Since January 2011, over 200 diagnostic fracture injection tests have been made into Argentina San Jorge basin reservoir layers. The objective of diagnostic fracture injection tests is to optimize hydraulic fracture technology and parameters in multi-sand and mud thin interstratifications by estimating pore pressure, permeability and closure stress in destination formation. The G-function, pressure match and pseudo-radial flow method were used to analyze pressure records. The pressure match method was used to analyze fracture shape created by the main fracture treatment. The ratios of fracture size were obtained in several work sections. This enhances the capability to design hydraulic fractures based on the reservoir conditions, with the optimum conductivity and fracture half-length to provide the required productivity over the life of the well. The sandscreen reasons were also depicted for sand and shale alternation.
The characteristics of production well were also studied. There is a big difference between perforation completion and fracture/perforation completion. Normally the wells with fracture have a relative good production. But the selection of potential layer is the biggest chanllege to improve production.
Application of this optimum process has resulted in improved well performance in the SJ basin well. Although the results presents are specific to the San Jorge Basin, the methodology and analytical techniques are valid in all basins.
Gaussian Process for Uncertainty Quantification of Reservoir Models
Authors: Hamdi Hamidreza , Hajizadeh Yasin , Sousa Mario Costa 
Published: October 2015

Abstract
Reservoir history matching is a computationally expensive process, which requires multiple simulation runs. Therefore, there is a constant quest for more efficient sampling algorithms that can provide an ensemble of equally-good history matched models with a diverse range of predictions using fewer simulations. We introduce a novel stochastic Gaussian Process (GP) for assisted history matching where realizations are considered to be Gaussian random variables. The GP benefits from a small initial population and selects the next best possible samples by maximizing the expected improvement (EI). The maximization of EI function is computationally cheap and is performed by the Differential Evolution (DE) algorithm. The algorithm is successfully applied to a structurally complex faulted reservoir with 12 unknown parameters, 8 production and 4 injection wells. We show that the GP algorithm with EI maximization can significantly reduce the number of required simulations for history matching. The ensemble is then used to estimate the posterior distributions by performing the Markov chain Monte Carlo (McMC) using a cross-validated GP model. The hybrid workflow presents an efficient and computationally-cheap mechanism for history matching and uncertainty quantification of complex reservoir models.
Worm-Like Micelles as a Mobility Control Agent for Chemical Enhanced Oil Recovery
Authors: Kumar S. , Awang Mariyamni , Ahmed Shuaib , Dehraj Naeem Ul. , Saleem Yasir Sheikh 
Published: October 2015

Abstract
In this Paper, Wormlike Micellar (WLM) solutions were studied as an alternative to polymeric mobility control agent in chemical enhanced oil recovery. In which, two compositions of WLM solutions were chosen and prepared in laboratory – Hexadecyltrimethylammonium Bromide/Sodium Nitrate and Three-(N, N-Dimethyloctadecylammonio) Propane-Sulfonate/Sodium Dodecyl Sulfate (TDPS)/Sodium Chloride. Then following experiments were conducted – thermal stability test, rheological measurements to account the effects of concentration, shears rates, salinity (NaCl = 3.5% w/v, CaCl2 = 0.05% w/v and MgCl2 = 0.05% w/v), and temperature (30 to 70 0C) on viscosity of these WLM solutions. Another stability test was conducted to test the effect of crude oil on WLM solution.
The results showed that WLM solutions have excellent rheological resemblances with HPAM polymer solutions. On addition of salts, the WLM solutions were highly tolerant over entire range of shear rates. At 70 0C, the thermal degradability of WLM solutions was less than HPAM polymer. Despite of all these significances viscosity of WLM solutions was deemed to the viscosity of water (1 cP) on mixing crude oil. It was due to strong interfacial activity between surfactants present in WLM compositions and crude oil. Such as, the IFT between crude oil and WLM solution was observed very low (0.3 to 0.55 mN/m) as compared to the typical system of water-oil (20 to 50 mN/m). Besides, core flooding was performed by mixed surfactant WLM solution (TDPS = 1.09% w/v, R = 0.55) at 70 0C.
The WLM solution produced an additional oil recovery of 10.9% beyond secondary recovery. Thus the results supported WLM solution to be potential mobility control for chemical EOR.