bluuebunny/crossref_metadata_2025_split huggingface dataset:
Kick Detection Capability of Oil-Based Muds in Well Control Situations
Authors: Linga Harald , Torsvik Anja , Saasen Arild 
Published: March 2016

Abstract
The understanding of kick and gas - oil-based drilling fluid (OBDF) interaction is essential for the planning and operational safety of drilling. The capability to detect gas kick at an early stage and to estimate the gas kick severity is critical.
In this respect the two classes of OBDFs are investigated, one with normal mineral base oil, and the other with linear paraffin base oil. The latter is often used in HPHT drilling applications.
The gas kick detection characteristics is determined by experimental studies of the methane-OBDF equilibrium conditions at pressure and temperature conditions ranging from STP conditions to conditions relevant for HPHT; 200 °C/1000 bar. The OBDF gas loading characteristics is derived from the determination of the two-phase envelope of methane and OBDF. The two-phase envelope towards single phase liquid is determined for selected temperatures and gas mass fraction of methane in the gas-liquid mixture. The equilibrium conditions are studied for both the two OBDFs and the associated classes of base oils; normal mineral base oil and linear paraffin base oil.
It is observed that the maximum methane gas loading capabilities for the two OBDFs are quite similar and follow a linear relation between max gas mass loading in the liquid vs. pressure at pressure below 400 bar. However at higher pressures the performance of the OBDFs differs distinctively, where far more gas can be absorbed in the OBDF with linear paraffin base oil. This OBDF enters into the dense phase region at pressures exceeding 400-450 bar, for which the solubility of gas into the liquid goes to infinity. The dense phase region is encountered at somewhat 100 bar higher with the normal mineral base oil, reflecting fare more attractive characteristics when it comes to the capability for gas kick detection and well control.
The findings illustrate that the selection of base oil for OBDF has an impact on the kick detection capability at HPHT as the gas loading capability and the dense phase region depends on the class of base oil selected for the OBDF. The results also indicate that the operational procedures should be adjusted according to which type of OBDF is used.
Plug and Abandonment Solution for Oilfield Decommissioning in the North Sea
Authors: Aguilar P. , Johnson C. R. , Salazar J. , Bogaerts M. 
Published: March 2016

Abstract
When wells have come to the end of their lives, it becomes necessary to plug and abandon them and return the seabed to its original condition. In the UK sector of the Central North Sea (CNS), an operator managed 6 fields comprising a total of 30 subsea wells in 7 clusters, required to be plugged and abandoned. These fields are among many that are coming to the decommission stage, with the over-riding requirement from the UK government being that of no leakage of hydrocarbons to the environment or between separate permeable geological zones.
The operator standards required the placement of two cement barriers of a minimum of 100-ft each for zonal isolation. The preferred route was to find the annular portion of the barrier by interpretation of ultrasonic imaging tool in combination with the cement bond (CBL) wireline logs used for cement evaluation service, then to set a 500-ft plug inside the casing opposite that zone. In the case that no barrier quality cement was identified in the annulus, section milling of the casing was undertaken to expose 100-ft of formation over which cement was placed.
A number of challenges were faced to design the cement slurry prior to the logging results. The setting depth may only have been confirmed a few hours before the cement job. To cover the possible setting depths and temperature ranges, laboratory testing consisted of performing temperature sensitivity tests on base slurries designed with a wide temperature range retarder, but still optimizing the system to minimize wait on cement (WOC) time.
A specialized high magnesium resistance (HMR) cement system that provides long-term zonal isolation and protects against cement degradation was identified as being best solution. The HMR cement is a blend of blast furnace cement and fly-ash, which reduces the cement permeability and limits the effect of alkaline brine corrosion.
Optimal plug placement was also required for long-term isolation. Specialized plug placement software that accounts for in-pipe and annular contamination, and fluid interface matching during pulling out of the plug was utilised. The slurry design and emplacement best practices will be summarized in this paper.
These subsea wells have been successfully plugged and abandoned by laying temporary, primary, secondary and environmental cement barriers by several different methods: inside casing, across section-milled windows, multi-annular, through scaled production tubing and through coiled tubing according to each particular well's condition. Success ratio was exceptionally high with all the long term barrier themselves being flawlessly placed and verified without any repeat job being required.
Use of Specially Treated Micronized Barite Fluid System with Wellbore Strengthening Approach to Drill Extremely Depleted Reservoir - HPHT Kvitebjørn Field, Offshore Norway
Authors: Ay Ahmet , Sagberg T. , Gyland K. R. , Askø Arne , Jordal Ole Henrik , Døssland Ørjan 
Published: March 2016

Abstract
The HPHT well, A-16A, was planned to test a certain part of the Kvitebjørn field in the North Sea for hydrocarbons in order to prove sufficient reserves to justify a field development. Drilling fluid selection and optimization in the planning phase was considered to be one of the key factors to be able to drill the pilot slim hole section through the Deco/Brent and Cook formations which brought challenges above the standard Kvitebjørn wells due to the risk of high depletion combined with high initial pressure.
The well was planned with a pilot hole, A-16, in order to test the drillability of the overlying strata and prove the absence of highly depleted sand formations. It was important to penetrate all possible depleted zones in the pilot well to verify that sidetrack can be drilled to produce from the Statfjord target. Oil based drilling fluid weighted with treated micronized barite (OB TMB) together with a wellbore strengthening approach was successfully implemented to achieve the pilot well goals.
Managed pressure drilling (MPD) and rig assist snubbing (RAS) equipment were rigged up and the 5 ¾-in pilot section was drilled through a 7-in temporary upper completion (TTRD) set in 9 7/8-in casing. MPD and RAS technologies were used in order to control the bottomhole pressure accurately and to ensure that the additional two barriers were maintained in the well at all times, even if the primary fluid barrier was lost due to crossflow.
The paper provides detail about the drilling fluid planning and execution for the pilot slim hole section; this includes the fluid design and work performed to select and optimize wellbore strengthening materials (WSM) package. The WSM package was optimized by sophisticated, formation fractured, laboratory tests based on the fracture size estimated by proprietary software. Initial formation losses observed while drilling were cured with the particles kept continuously in the fluid, which eliminated the use of extra lost circulation material (LCM) pills or cement slurries. The section was then drilled with more than 500 bar (7252 psi) hydrostatic overbalance (including MPD back pressure), with no further formation losses and without differential sticking incidents while taking pressure points in the extremely depleted zones.
The interval was drilled through extremely depleted formations with the highest overbalance drilling in the operator's experience. Superior integrity of the WSM prevented losses and minimized fluid treatments; this reduced the overall costs with minimal logistics. Low density (~1.5 specific gravity) WSM prevented particle settling in the well or in the drillstring and within the surface equipment, which proved the reliability of the design for MPD sections.
Carbon Dioxide Injection and Resultant Alteration of Weber Sandstone (Pennsylvania-Permian), Rangely Field, Colorado
Authors: Bowker K. A. , Shuler P. J. 
Published: March 2016

Abstract
Geologic interpretations made during the current EOR (enhanced oil recovery) project at Rangely field (Rio Blanco County, Colorado), have made interesting connections between alteration of reservoir mineralogy and texture, changes in produced water composition, and increased production problems.
Carbon dioxide is being injected into the Weber Sandstone in portions of Rangely field. The carbon dioxide injection is part of a very successful tertiary recovery project initiated in late 1986. The bottom-hole pH of Weber brine has decreased from approximately 7.5 to 4.5 with the addition of C02. At Rangely, the Weber is composed mostly of fine-grained eolian sandstone with intercalated (and nonproductive) fluvial sandstones, siltstones, and shales. Much of the Weber is partially cemented with carbonate minerals, including ferroan calcite and ferroan dolomite. Clay minerals, predominantly illite, are also present.
Changes in the chemistry of produced water are associated with alteration of reservoir mineralogy. The C02 flood has caused a substantial increase in the concentrations of iron, calcium, magnesium, and strontium in the produced brine. The amounts of increase is directly related to the volume of C02 produced in each well. This increase resulted from the dissolution of carbonate cements, authigenic clays, and detrital feldspars. An increase in the calculated scaling potential of the produced water is a result of this change in chemistry. Although barium and sulfate concentrations generally have not changed with the C02 injection, produced water from some wells has experienced large changes in barium and sulfate concentrations. The result is an increased tendency for barite scale to precipitate in these wells. An increase in chloride concentration indicates that previously segregated portions of the reservoir, which contained very saline original formation water, have been accessed by the carbonated brine.
Effect of Indaziflam Applications on ‘Tifway 419’ Bermudagrass Growth
Authors: Jeffries Matthew D. , Gannon Travis W. , Ou Ling 
Published: March 2016

Indaziflam {N‐[(1R,S)‐2,3‐dihyrdo‐2,6‐dimethyl‐1H‐inden‐1‐yl]‐6‐(1‐fluorethyl)1,3,5‐triazine‐2,4‐diamine} is a preemergence herbicide for annual weed control in turfgrass systems. Following indaziflam U.S. registration in 2010, sporadic cases of hybrid bermudagrass (HB) injury were reported. Field research was conducted from 2012 to 2014 evaluating indaziflam application rates [16 followed by 16 (28 d), 33, 49, or 65 g a.i. ha−1] and timings (fall‐only, fall‐plus‐spring, or spring‐only) in two environments (reduced sunlight [RS] and full sunlight [FS]) to elucidate their effect on HB growth. In Year 1, differences were not detected, while in Year 2 HB cover varied between environments. In Year 2, HB cover in the RS environment treated with 49 and 65 g ha−1 had 36 and 64% less visual cover 12 wk after initial spring treatment than the FS environment, respectively. Within the RS environment, indaziflam also reduced HB visual cover compared to the nontreated (77% cover). A bioassay study conducted with soil cores collected from field plots suggested HB cover reduction was minimally affected by indaziflam‐soil bioavailability, as perennial ryegrass biomass was not reduced beyond a 2.5‐cm depth. Weather conditions varied between years, with air temperatures ≤0°C occurring more frequently and to a greater magnitude in Year 2. The weather, coupled with reduced solar radiation in the RS environment may have contributed to HB cover reduction in Year 2. Overall, indaziflam applications to established HB in areas with suitable growth conditions were safe; however, unacceptable HB cover reductions were observed in areas with poor growth conditions.

Indaziflam is safe on established bermudagrass grown in appropriate conditions.
Bermudagrass‐indaziflam tolerance decreased when applied in a reduced sunlight setting.
Severe winter climatic conditions exacerbated bermudagrass‐indaziflam injury.
Bone Defect Regeneration by a Combination of a β-Tricalcium Phosphate Scaffold and Bone Marrow Stromal Cells in a Non-Human Primate Model
Authors: Masaoka Tomokazu , Yoshii Toshitaka , Yuasa Masato , Yamada Tsuyoshi , Taniyama Takashi , Torigoe Ichiro , Shinomiya Kenichi , Okawa Atsushi , Morita Sadao , Sotome Shinichi 
Published: March 2016

Background:Reconstruction of large bone defects is a great challenge in orthopedic research. In the present study, we prepared composites of bone marrow-derived stromal cells (BMSCs) and β-tricalcium phosphate (β-TCP) with three novel aspects: proliferation of BMSCs with continuous dexamethasone treatment, cell loading under low pressure, and use of autologous plasma as the cell loading medium. The effectiveness of the resulting composite for large bone-defect reconstruction was tested in a non-human primate model, and the bone union capability of the regenerated bones was examined.Materials and Methods:Primary surgery: Bone defects (5 cm long) were created in the left femurs of nine cynomolgus monkeys with resection of the periosteum (five cases) or without resection (four cases), and porous β-TCP blocks were transplanted into the defects. Secondary surgery: Bone marrow aspirates harvested from seven of the nine monkeys were cultured with dexamethasone, and BMSCs were obtained. BMSCs were suspended in autologous plasma and introduced into a porous β-TCP block under low-pressure conditions. The BMSC/β-TCP composites were transplanted into bone defects created at the same sites as the primary surgery. Bone union evaluation: Five regenerated femurs were shortened by osteotomy surgery 8 to 15 months after transplantation of the β-TCP/BMSC composites, and bone union was evaluated radiographically.Results:After the primary surgery and treatment with β-TCP alone, one of the five periosteum-resected monkeys and two of the four periosteum-preserved monkeys exhibited successful bone reconstruction. In contrast, five of the seven cases treated with the β-TCP/MSC composite showed successful bone regeneration. In four of the five osteotomy cases, bone union was confirmed.Conclusion:We validated the effectiveness of a novel β-TCP/BMSC composite for large bone defect regeneration and confirmed the bone union capability of the regenerated bone.
Altered Multifidus Recruitment During Walking in Young Asymptomatic Individuals With a History of Low Back Pain
Authors: Smith Jo Armour , Kulig Kornelia 
Published: March 2016

Study Design Controlled laboratory study, with a case-control, cross-sectional design. Background Individuals with low back pain have impaired activation of the multifidus during postural adjustments and increased activity of the erector spinae musculature during walking. However, it is unclear whether these alterations in muscle activity are evident during locomotion in individuals with a history of low back pain when they are between symptomatic episodes. Objectives To compare paraspinal muscle activity in young, healthy individuals and young individuals with a history of low back pain during walking turns. Methods Fourteen asymptomatic individuals with a history of low back pain and 14 controls performed 90° walking turns at both a self-selected speed and a fast speed. The duration and amplitude of activity in the deep fibers of the multifidus and the lumbar and thoracic longissimus were quantified using intramuscular electromyography. Results There was a significant speed-by-group interaction for the duration of multifidus activity (P = .013). Duration of activity increased from the self-selected speed to the fast locomotor speed in the controls, but decreased in the individuals with a history of low back pain (P = .003). Self-selected speed was the same in both groups (P = .719). There was a trend toward a significant association between group and the direction of change in the duration of deep multifidus activity (χ2 = 0.058). Duration of thoracic longissimus activity and amplitude of multifidus and thoracic longissimus activity increased similarly in both groups from the self-selected to the faster speed. Conclusion Even between symptomatic episodes, young individuals with a history of low back pain demonstrated altered recruitment of the deep fibers of the lumbar multifidus in response to changing locomotor speed during walking turns. J Orthop Sports Phys Ther 2016;46(5):365–374. Epub 21 Mar 2016. doi:10.2519/jospt.2016.6230
Novel Lightweight Biopolymer Drilling Fluid for Underbalanced Drilling
Authors: Nee Lim Symm , Khalil Munawar , Jan Badrul Mohamed , Ali Brahim Si 
Published: March 2016

Abstract
This research centres on optimizing the formulation of a water-based lightweight biopolymer drilling fluid using Design Expert for underbalanced drilling (UBD). Response Surface Methodology (RSM) was selected as a viable means to obtain the optimized drilling fluid formulation. Concentrations of four main raw materials (glass bubbles, clay, xanthan gum and starch) were varied in a suitable range to obtain the formulation with the desirable density, plastic viscosity (PV) and yield point (YP) for UBD application. Based on the results, the optimized drilling fluid can be formulated with 24.46% w/v of glass bubbles, 0.63% w/v of clay, 0.21% w/v of xanthan gum and 2.41% w/v of starch. The desirability factor, d for this optimum condition selected is 0.628. The mathematical models generated by RSM were able to predict the three response parameters well, as the experimental values were found to be in good agreement with the predicted values. The error is less than 1.0, standard deviation less than 0.5 and the accuracy is more than 98.5%. All mathematical models were quadratic in nature. The model used to predict the PV has an inverse square root transform. This drilling fluid is considered to be less harmful to the environment as it is water-based and, at the same time, composed of natural polymers (xanthan gum and starch) which are biodegradable. With this novel formulation, we could expect to drill more wells in underbalanced conditions to improve production of oil.
Case Study: Integrated Strategy Solves Well Test Issues in Deep-Water and Heavy-Oil Environments
Authors: Zhong Cheng , Liang Zhang , Zhengli Liu , Junbin Zhang , Yuezeng Wang , Kun Cheng 
Published: March 2016

Abstract
As the operator, CNOOC completed drilling two exploratory wells in a deep-water field of the Republic of Congo from May to November of 2013, in 600 m of water depth. Indications of oil and gas- heavy oil layer, gas layer and thin oil layer were found in the E-1 well according to logging data analysis. There are many challenges for the operator and service companies to perform the appraisal of this heavy oil reserve in a deep-water offshore environment, such as operational cost control, low temperature near the seafloor/mud line, heavy oil flow assurance, sand control, etc. In order for the well test to be effective, all the above issues must be fully understood and methodology employed that will reduce the chance that operational risks will occur.
This paper presents an integrated well test program of the E-1 well developed and implemented for reservoir characterization and formation evaluation in the Congo basin. The program used a combination of various formation evaluation techniques such as wire wrapped screen sand control, PCP with electric heating rod and insulation tubing, hydrate prevention, emergency response in complex condition. The integrated well test program was designed and modified to meet the project delivery timeline and cost constraints, while responding to the challenge of properly testing the oil/gas reservoirs.
This paper also gives the data analysis results and summarizes the encountered problems and learned lessons from field operations.
The treatment practices and gained experiences from the field operation presented here provide valuable guidance for future deep-water heavy oil exploration and development operations.
Integrated Wellbore Suveillance Techniques for Effective Reservoir Management Plan
Authors: Saadat Aliasghar , Rahman M. Redzuan A. , Masoudi Rahim , Salim Sharina M. , Othman Mohamad , Shnaib Fathi Younis , Karantharath Radhakrishnan 
Published: March 2016

Abstract
Production optimization and improved recovery efficiency while reducing operating and capital expenditure has been the main goal of the operators, and makes it imperative under the current oil prices. Reservoir Management Programme (RMP) is a comprehensive and integrated process of establishing control over hydrocarbons appraisal, extraction, voidage replacement, and optimizing production and reservoir performance, and it is the key to achieving maximum recovery. Monitoring well and reservoir performance from initial completion to abandonment is critical to ensure efficient operation, optimum economics, and safe environment. Tracking production rates, water cut, wellhead pressure, casing pressure, well integrity, and planning recompletion, workovers, sidetracks, in-fill drilling, enhanced oil recovery etc. will require close watch, accurate analysis, and timely execution at considerable cost and effort. Therefore, it is critical to stay up-to-date on the latest developments in technological advancements in this area, be judicious in the methods used in acquiring the right data at the right time, and more importantly, integrating all acquired data to discern performance patterns, predict future behavior, and avert any problems. More detailed understanding of reservoir characterization and reservoir physics are the need of the hour to be efficient and successful in the various stages of the exploitation of the reservoir.
Furthermore, advances in horizontal drilling, smart well completions, deep-sea drilling, and highly complex operation, have changed the playing field and rendered many old conventional tools inadequate to meet the new challenges. For example, rates from some intervals along a horizontal well can be too low to be measured by a typical flowmeter. The cost of measuring reservoir pressure in individual layers can be cost prohibitive, especially once the completion is in place. Reservoir characterization, understanding lateral continuity, and permeability anisotropy can be time consuming and expensive. Locating the source of a casing pressure accurately, quickly, and without having to mobilize special equipment (rig-less) is critical.
This paper illustrates the application of the above principles by showing actual cases, methodology of data acquisition and processing, focusing on the added value from the new information.