bluuebunny/crossref_metadata_2025_split huggingface dataset:
Phase-Behavior Modeling of Oils in Terms of Saturates/Aromatics/Resins/Asphaltenes Fractions
Authors: Gutiérrez D.. , Moore R. G. , Mehta S. A. , Ursenbach M.. , Bernal A.. 
Published: October 2018

Summary
One of the key steps toward improving the predictability of air-injection-based processes relies on the development of accurate phase-behavior models of the oil.
Historically, for in-situ combustion (ISC) in heavy oils and bitumens, phase behavior was often ignored because the physical aspects of the process (e.g., distillation) were not considered to be as significant as the oxidation reactions. However, this step is important for several reasons. First, the compositional model should reflect the phase behavior of the original fluids. Second, reaction rates are dependent on the concentrations of the reactants, which in turn are affected by the volatility of the components. This is particularly important for lighter oils (but not unimportant for heavier oils), where the phase equilibrium between the liquid and vapor can have a significant effect on the flammability range for vapor-phase combustion at given temperature and pressure conditions. Finally, for the case of lighter oils, a good phase-behavior model is required to capture the compositional effects of the resulting flue-gas drive.
This study presents a practical work flow to develop a phase-behavior model in terms of saturates/aromatics/resins/asphaltenes (SARA) fractions that is aligned with the reaction-modeling approach used in most kinetic models. The methodology requires conventional-oil-characterization (i.e., dependent on distillation cuts) and conventional-phase-behavior experiments (e.g., differential liberation), as well as oil characterization in terms of SARA fractions.
The first step of the method consists of splitting the heaviest oil fraction (i.e., plus fraction), followed by lumping all of the single-carbon-number (SCN) components, in such a way that the new oil characterization honors the SARA data available, such as composition and the physical properties of each fraction (e.g., molecular weight). In addition, the gas components (e.g., methane) would be treated as additional components as necessary. The second step is to tune an equation of state (EOS), in terms of the SARA-based model, to match the relevant laboratory experiments. Finally, the tuned EOS would be used to export the equilibrium constants (K-value tables) to the thermal numerical simulator.
Different examples on the application of the phase-behavior-modeling work flow are presented and discussed in detail for heavy and light oils. This work opens up opportunities to model the ISC process for any oil (i.e., light or heavy) using the currently available kinetic models, which in turn is an important step toward improving the predictability of ISC processes using reservoir simulation.
Can 25-cp Polymer Solution Efficiently Displace 1,600-cp Oil During Polymer Flooding?
Authors: Seright R. S. , Wang Dongmei , Lerner Nolan , Nguyen Anh , Sabid Jason , Tochor Ron 
Published: October 2018

SummaryThis paper examines oil displacement as a function of polymer-solution viscosity during laboratory studies in support of a polymer flood in Canada's Cactus Lake Reservoir. When displacing 1,610-cp crude oil from field cores (at 27°C and 1 ft/D), oil-recovery efficiency increased with polymer-solution viscosity up to 25 cp (7.3 seconds−1). No significant benefit was noted from injecting polymer solutions more viscous than 25 cp. Much of this paper explores why this result occurred. Floods in field cores examined relative permeability for different saturation histories, including native state, cleaned/water-saturated first, and cleaned/oil-saturated first. In addition to the field cores and crude oil, studies were performed using hydrophobic (oil-wet) polyethylene cores and refined oils with viscosities ranging from 2.9 to 1,000 cp. In field cores, relative permeability to water (krw) remained low, less than 0.03 for most corefloods. After extended polymer flooding to water saturations up to 0.865, krw values were less than 0.04 for six of seven corefloods. Relative permeability to oil remained reasonably high (greater than 0.05) for most of the flooding process. These observations help explain why 25-cp polymer solutions were effective in recovering 1,610-cp oil. The low relative permeability to water allowed a 25-cp polymer solution to provide a nearly favorable mobility ratio. At a given water saturation, krw values for 1,000-cp crude oil were approximately 10 times lower than for 1,000-cp refined oil. In contrast to results found for the Daqing polymer flood (Wang et al. 2000, 2011), no evidence was found in our application that high-molecular-weight (MW) hydrolyzed polyacrylamide (HPAM) solutions mobilized trapped residual oil. The results are discussed in light of ideas expressed in recent publications. The relevance of the results to field applications is also examined. Although 25-cp polymer solutions were effective in displacing oil during our corefloods, the choice of polymer viscosity for a field application must consider reservoir heterogeneity and the risk of channeling in a reservoir.
Reducing Artificial Lift Surface Conversion Costs in a Unconventional Oil Field
Authors: Weiss Clark , McGee Todd , McAdam Kristen 
Published: October 2018

Abstract
The Tourmaline Oil Corporation's light oil play (The Field) utilizes electrical submersible pumps (ESP's) for the dewatering and initial production (IP) phase. Sucker rod pumps are then used as the main artificial lift technology to produce The Field. The typical procedure is to convert these wells to pump and rods after the first ESP failure or after the well ceases to flow naturally. Constant changing of the lift systems on each well incurs costs, requires manpower and creates exposure with the need for surface facilities work.
The recent economic downturn applied focus on reducing costs while optimizing production. A single wellhead that could accommodate flowing wells, ESP's, rod pumps and gas lift without the need to change the flowline configuration would save money and minimize production downtime. To develop this technology Tourmaline collaborated with industry leaders in wellhead penetration and rod pumping blow out preventers (BOP's) to design and engineer such a wellhead. The multi-function BOP will master ESP, rod pumps, natural flow and gas lift. After the multi-function BOP development was complete it was trialed in a controlled environment then installed on multiple wells within The Field.
The product developed consists of combination tubing hanger and production wellhead. The multi-function wellhead includes dual master valves, dual rod BOP's, ESP capillary feed-through and gas lift capabilities with two flowline outlets. The final product is only thirty one and a half inches in height, making it compact, and operationally ergonomic. There have also been efficiencies realized from this wellhead including modular wellhead skids, downhole artificial lift combination deployment and reduced servicing costs. The surface conversion costs have been reduced by 95%.
Due to the unconventional well flowing regimes and artificial lift practices Tourmaline Oil faces in The Field the need for new technology was identified. By teaming up with industry leaders an innovative and unique multif-function BOP wellhead was developed. The product has been installed throughout The Field with great success and has inspired other advancements in oil field efficiency.
Identifying Analogue Fields in PCP Applications Using Classification Trees
Authors: Sheldon John , Alhanati Francisco , Skoczylas Paul 
Published: October 2018

Abstract
Operators want to benchmark the run-life performance of their progressing cavity pumping (PCP) systems against that of other industry players to ensure that they are achieving the best run-life they can. When doing such benchmarking analyses, it is important to benchmark against analogue fields with similar application characteristics to ensure that the results are meaningful. However, identifying proper analogue fields is not straightforward as there are many parameters that one may potentially consider to define what a similar application is. To date, there is no tool available to assist operators in identifying analogue fields in PCP applications for benchmarking PCP run-life performance.
This paper presents the approach taken to develop and validate a PCP Classification Tree that defines application classes, based on relevant application characteristics, which can be used by operators to assist with identifying potential analogue fields (i.e. based on characteristics that have proven influential on PCP run-life performance). The difficulties encountered during the development are described. The proposed PCP Classification Tree, which was built using a comprehensive worldwide database of PCP installations that includes both run-life and application characteristics data, is also presented in the paper. According to the proposed PCP Classification Tree, good analogue operations, with similar average run-life performance, are those that have similar downhole operating temperature, and similar fluid characteristics, such as fluid mixture viscosity, oil density, H2S, CO2 and solids content.
Use of Run-Life Measures in Estimating Artificial Lift System Reliability
Authors: Skoczylas Paul , Alhanati Francisco , Sheldon John , Trevisan Francisco 
Published: October 2018

Abstract
Operators generally want to reduce well down-time and repair/replacement costs by improving the reliability of their Artificial lift (AL) systems. In order to understand if actions taken to improve reliability are effective, one must track the AL system run-life. This paper discusses run-life measures commonly used in the AL industry and provides recommendations for when each run-life measure should be used. Synthetic data, generated using random runtime and failure data from known statistical distributions, is used to illustrate the effect of various factors, such as selecting equipment with higher inherent reliability, on the resulting measured run-life. This paper also presents several pitfalls that should be avoided when selecting run-life measures for comparing equipment or implementing operator-vendor alliance contracts.
Near Real-Time Monitoring of PDC Bit Condition and Associated NPT Mitigation Using Online Alkene Detection
Authors: Regan M. , Carcione E. , Martocchia A. 
Published: October 2018

Abstract
This paper will present an innovative new methodology for realtime monitoring of bit condition – and hence drilling efficiency - using surface measurement of alkene gases artificially created at-bit by the bit as its condition deteriorates.
A drop in ROP can be an effect of a variety of causes, often disparate in nature. Can performance be improved by a change in drilling parameters and, if so, for how much further will these parameters remain effective? Is there some form of drilling dysfunction that is resulting in inefficient transfer of energy into drilling action? Is there a change in lithology and, if so, is the bit still appropriate and viable in this new formation? Or is the bit simply approaching the end of its useful life through wear earlier than anticipated, in which case at what point does it become less economic to continue drilling at low ROP and POOH instead?
The decision to POOH to change a bit that is perceived to be under-performing can be costly if the bit is found to be in workable condition and the trip is therefore premature. Unnecessary trips are a major source of non-productive time (NPT) so any trusted source of indicative information on bit condition adds valuable context and confidence to operational decision-making.
Realtime monitoring of contaminant alkenes provides timely indications to drillers of the degree of bit wear, mitigating invisible lost time (ILT) through excessive prolongation of an ineffectual dulled bit run, and reducing the risk of its potentially catastrophic failure. Field-based case histories are presented supporting the complementary relationship of alkene generation to other indicators of inefficient drilling, how alkene presence can assist in drilling dysfunction diagnosis, and a prototype of a software application based on alkene levels that informs decision-makers of the ‘tipping point’ at which objective commercial factors support pulling a dull bit.
Fracture Packing in Previously Gravel-Packed Well Using Single-Trip Multizone System
Authors: Deng Jianming , Ma Yingwen , Zhang Ming , Qian Jiacheng , Fang Chao , Wang Qiang , Wang Xiaobo 
Published: October 2018

Abstract
This paper details the process of designing and executing a frac pack operation in a previously gravel-packed formation. Challenges and solutions are discussed as well as the methods used to properly squeeze fluid and proppant into the formation.
During the last 13 years in China, a single-trip multizone (STMZ) gravel-packing system has been widely used in Bohai Bay for sand control. Most of the wells were initially completed using high-rate water packing methods and then were sidetracked once production reduced to a certain level. However, operators desired a lower-cost work over plan. The proposed method involved recompleting a previous well by running service tools into the well to perform fracture packing within the existing multizone gravel-pack completion. High-viscosity fluid was pumped into the formation as a prepad, and then formation fracture packing was performed.
The successful treatment execution presented in this paper demonstrates the process of cleaning the wellbore for recompletion. Using the STMZ system proved the downhole service tool could be safely tripped back in and out of hole in the same trip following fracture packing of a previously gravel-packed multizone well completion. The method also shows that, through careful preplanning and designing of the tool and treatment, the risk of failure caused by a stuck tool string, unwanted fluid loss, or premature screenout can be minimized. The job execution and lessons learned along the way can also provide a guideline for improvement of future treatments in similar situations.
This paper presents the first successful fracture packing application in a previously gravel-packed well. The method presented provides a new method to enhance production of mature wells without performing a sidetrack, significantly reducing costs by recompleting the well.
Optimized Diversion System Applied in Stimulation Treatments in a Highly Naturally Fractured Carbonate Formation: Successful Case Histories
Authors: Ramirez Cristian , Campos Katya Rosa , Gonzalez Alfredo Daniel 
Published: October 2018

Abstract
Chemical diverter systems, such as relative permeability modifiers (RPMs), can significantly reduce effective permeability, mainly to aqueous-based fluids (e.g., acids), where the fluid enters into the interval being treated. Graded salt is a granular solid used at all temperatures that has a wide particle-size distribution (PSD) for bridging and sealing to provide effective diversion of treating fluids. This combined with an RPM fluid can help divert the entire interval during a matrix-acid stimulation. This paper discusses a review of wells treated, with excellent results, using such a chemical and bridging diversion system (CBDS) in different fields in the southern region of Mexico.
If a formation has zones containing a large number of open, natural fractures, the resulting tendency is for treatment fluids to flow into the zone(s) with the highest effective permeability or the least amount of damage instead of creating a uniform distribution over the entire interval, as is necessary. An important characteristic for a diverter product is creating a temporary skin effect during the injection of the treatment that leaves no permanent damage or that can later be removed or dissolved.
The focus of this study was on gathering more detailed information for the selection of the diverter, treatment design, and operational procedures. Additionally, the learning curve is presented associated with the challenge of stimulating a specific zone within a complex mechanical wellbore and selecting the correct candidate for applying a schedule of mechanical diversions and acid stimulations.
Laboratory study data are included to illustrate how the diverting process physically manifests, which is used to substantiate the field designs. Understanding how chemical diverters interact with the formation rock and fluid is fundamental to selecting the proper product for a specific treatment application.
Intelligent Completions First Implementation of Injector Multi-Zones – Injectivity Optimization and Efficiency for IOR Integrated Operation
Authors: Razak M. Firdaus , Khalid Aizuddin , Sapian Nik Fazril , Madzidah Asba , Samuel Orient Balbir , Khalid M. Zaidan , Mohd Shamsulbahri B. , Bakar M. Farris , Salih Mohamed Sharief , Ruvalcaba Jazael Ballina , Sadan Nur Syazana , Misron M. Al-Perdaus , Afzan A. Satar , Jamal Ajmal Faliq , A'akif Nurul Aula , Mohr Ludovic , Tajuddin Nor Baizurah , Kalidas Sanggeetha , Faizah P. Mosar , Goh Gordon , Tan Tina , Palanisamy Ravishankar , Luke Darren 
Published: October 2018

Abstract
The ‘B’ Field is located about 40 KM, offshore Sarawak and was discovered in 1967 with 70-80 m water depth. Structurally, ‘B’ field is charaterised by a simple relatively flat, low-relief domal anticline which is bounded to the north and south by the north-hading growth faults. The major faults are acted as effective lateral seal, which is indicated by the difference in the fluid type and fluid contacts across those faults. ‘B’ field consist of multiple hetereogenous sandstone reservoirs with permeability and porosity ranging from 25 −1700 mD and 16 −29% respectively.
‘B’ Field injectivity conformance for reservoir pressure support is very crucial as the field is undergoing severe depletions over years and unable to meet the production target. The Operator realized the importance in order to further increase the recovery factor, hence has included ‘B’ field in the Improved Oil Recovery (IOR) project to boost the production and prolong ‘B'field's life. Based on comprehensive IOR/EOR screening study, water injection process has been identified as the most amenable IOR process in ‘B'field. Hence, in Phase 1 drilling campaign, two (2) water injectors were drilled in 2016 in order to achieve the target oil recovery. Both well BWI-01 and BWI-02 were completed with Intelligent completions (IC) and expected to come online in Q4 2018.
This paper further discusses the injection strategy in ‘B’ field multi-zones to meet the zonal injectivity and reservoir zonal voidage replacement requirement for pressure maintenance over field production life. The discussion covers the reservoir characteristics and zonal injectivity challenges with surface constraints that require intelligent completions solution for IOR phase. Completions architecture and customized metallurgy needs is crucial to meet operational challenges. Fit-for-purpose and maintaning development cost is pre-requisite to achieve well injection performance for optimal production
The Triaxial Limit and Safety Factor of an Anisotropic CRA Tubular
Authors: Sathuvalli Udaya B , Suryanarayana P. V. , Rahman Shaikh , Chandrasekhar Sharat 
Published: October 2018

Abstract
Tubulars made with Corrosion Resistant Alloys (CRA) exhibit a moderate degree of transverse anisotropy. This results in a lower yield strength in the plane perpendicular to the rolling axis of the tubular. In addition, cold work during mill finishing introduces yield strength asymmetry along the axis.
The majority of CRA tubulars are low do/t (~ 10 to 15) production strings and their design is usually driven by pressure and tension. Given the reduced yield strength in the hoop direction (as compared to axial yield strength), a rigorous method to assess the effect of yield strength anisotropy on the triaxial limits of the pipe is needed. Though there is a substantial body of mature literature on anisotropy in metals and manufactured composites, anisotropy of tubulars has received little attention by tubular designers.
In this context, we use Hill's celebrated criterion (Hill 1950) for the yielding of anisotropic metals to develop an equation for the triaxial limits of a hollow cylinder and show that the currently used isotropic triaxial ellipse is a special case of the general limit. Also, by recognizing that purely elastic load excursions do not alter the yield surface, we extend the aforementioned triaxial limit to tubulars with tension-compression asymmetry along the tube axis. Finally, based on the notion of a strength utilization factor, we propose a method to determine the triaxial safety factor for anisotropic CRA tubulars. This method is consistent with the definition of the triaxial safety factor for isotropic tubulars.
Managing Losses with Controlled Mud Level Drilling
Authors: Smaaskjar Geir , Bergseth Einar , Hollman Landon , Arseneault Leo , Leggett Craig , Fossli Børre , Claudey Eric 
Published: October 2018

Abstract
Since 2016, Lundin Norway has used Enhanced Drilling's EC-Drill System to enable Controlled Mud Level (CML) drilling in the Barents Sea. The CML process allows control of the mud level in the riser in order to mitigate and manage losses while drilling, coring, tripping, cementing casing/liner, wireline operations, and well abandonment operations. With a sub-sea pump module (SPM) docked to a modified riser joint, pressure sensors on the riser and mud return line connected to the top-side, the EC-Drill equipment was able to precisely control the fluid level in the riser and manage the bottom hole pressure while drilling through potential loss zones in naturally fractured and potentially karstified carbonate formations. This paper discusses the CML system used during the project, as well as the drilling, tripping, and cementing strategy, examples of how the system was used to reduce wellbore ballooning, reduce losses during drilling, cementing and well abandonment, and several key lessons learned over the the past seven exploration and appraisal well operations.
The ability to raise and lower the riser level to manage the loss rate allowed the CML process to be used during drilling / coring operations, cementing of 7" liners and 9 5/8" casing, as well as wireline operations and well abandonment. Once the SPM and modified riser joint were deployed with the marine drilling riser and SS BOP, the system is ready for use. This allowed using the CML process in hole sections as large as 17 ½" with minimal modification of conventional drilling practices, or sacrificing ROP due to restricted flow rates. The accuracy of the riser pressure sensors on the modified riser joint allowed the system to be used while tripping to reduce surge pressures while running in hole. The system also added value during cement jobs by managing the wellbore pressure profile and return flow throughout the cement circulation and displacement. During plug and abandonment operations critical path time and cost have been reduced by managing losses to an acceptable rate during casing retrieval. The CML process has become an integral part of the operation from start to finish for Barents Sea operations for Lundin.