bluuebunny/crossref_metadata_2025 huggingface dataset:
Comparison of Glycemic and Metabolic Control in Youth With Type 1 Diabetes With and Without Antipsychotic Medication: Analysis From the Nationwide German/Austrian Diabetes Survey (DPV)
Authors: Galler Angela , Bollow Esther , Meusers Michael , Bartus Bela , Näke Andrea , Haberland Holger , Schober Edith , Holl Reinhard W.
Published: March 2015

OBJECTIVE

The objective of this study was to explore metabolic risk factors and glycemic control in youth with type 1 diabetes treated with typical or atypical antipsychotics.

RESEARCH DESIGN AND METHODS

Data for 60,162 subjects with type 1 diabetes up to the age of 25 years registered in the nationwide German/Austrian Diabetes Survey were included in the analysis. BMI; HbA1c; treatment strategy; prevalence of hypertension, dyslipidemia, microalbuminuria, and retinopathy; frequency of hypoglycemia and diabetic ketoacidosis (DKA); and immigrant status among subjects treated with typical or atypical antipsychotics were compared with those without antipsychotic medication and analyzed by regression analysis.

RESULTS

A total of 291 subjects with type 1 diabetes (median diabetes duration 7.2 years) received antipsychotic medications (most commonly risperidone). Subjects treated with antipsychotics had a higher BMI (P = 0.004) and dyslipidemia was more frequent (P = 0.045) compared with subjects not receiving antipsychotic medication. Frequencies of severe hypoglycemia and DKA were significantly higher in subjects receiving antipsychotics (P < 0.001). The prevalences of hypertension, microalbuminuria, and retinopathy were not different. In subjects treated with typical antipsychotics, glycemic control did not differ compared with those who did not receive antipsychotic medications. By contrast, subjects treated with atypical antipsychotics had higher HbA1c levels (P = 0.022).

CONCLUSIONS

This analysis from a real-life survey demonstrated that subjects with antipsychotic medication had worse glycemic control and a higher rate of acute complications compared with those without antipsychotic medication. Health care teams caring for youth with type 1 diabetes taking antipsychotic medication need to know about these findings. We suggest monitoring metabolic risk factors as well as providing diabetes education about prevention of acute complications.
Association Between Cardiorespiratory Fitness and the Determinants of Glycemic Control Across the Entire Glucose Tolerance Continuum
Authors: Solomon Thomas P.J. , Malin Steven K. , Karstoft Kristian , Knudsen Sine H. , Haus Jacob M. , Laye Matthew J. , Kirwan John P.
Published: March 2015

OBJECTIVE

Cardiorespiratory fitness (VO2max) is associated with glycemic control, yet the relationship between VO2max and the underlying determinants of glycemic control is less clear. Our aim was to determine whether VO2max is associated with insulin sensitivity, insulin secretion, and the disposition index, a measure of compensatory pancreatic β-cell insulin secretion relative to insulin sensitivity, in subjects representing the entire range of the glucose tolerance continuum.

RESEARCH DESIGN AND METHODS

A cohort of subjects (N = 313) with heterogeneous age, sex, BMI, and glycemic control underwent measurements of body composition, HbA1c, fasting glucose, oral glucose tolerance (OGTT), and VO2max. OGTT-derived insulin sensitivity (SiOGTT), glucose-stimulated insulin secretion (GSISOGTT), and the disposition index (DIOGTT) (the product of SiOGTT and GSISOGTT) were measured, and associations between VO2max and these determinants of glycemic control were examined.

RESULTS

A low VO2max was associated with high HbA1c (r = −0.33), high fasting glucose (r = −0.34), high 2-h OGTT glucose (r = −0.33), low SiOGTT (r = 0.73), and high early-phase (r = −0.34) and late-phase (r = −0.36) GSISOGTT. Furthermore, a low VO2max was associated with low early- and late-phase DIOGTT (both r = 0.41). Interestingly, relationships between VO2max and either glycemic control or late-phase GSISOGTT deteriorated across the glucose tolerance continuum.

CONCLUSIONS

The association between poor cardiorespiratory fitness and compromised pancreatic β-cell compensation across the entire glucose tolerance continuum provides additional evidence highlighting the importance of fitness in protection against the onset of a fundamental pathophysiological event that leads to type 2 diabetes.
Wear and corrosion resistant laser coatings for hydraulic piston rods
Authors: Tuominen J. , Näkki J. , Pajukoski H. , Miettinen J. , Peltola T. , Vuoristo P.
Published: March 2015

Hydraulic piston rods on oil and gas drilling platforms, hydro-power stations, chemical plants, and underground mines are exposed to severe tribo-corrosive conditions under static and dynamic mechanical loads. Piston rods made of carbon, quenched and tempered (QT) and stainless steels are frequently surface coated with methods such as thermal spraying, hard chrome plating, and overlay welding. Unfortunately, several premature failures have been reported particularly in marine applications due to insufficient coating properties. Laser cladding has recently drawn lot of attention in this field due to high coating quality and significant improvements in productivity. In this study, several potential Fe-, Ni-, and Co-based alloys were laser clad on carbon and QT steels. Their corrosion and mechanical performances were explored in long-term salt spray, immersion, hardness, abrasive wear, and four-point bending fatigue tests. Most of the laser coatings outperformed hard chrome in corrosion properties, but hardness values were somewhat lower. In single point abrasion tests (scratch tests), the hardest laser coatings, however, outperformed hard chrome due to brittle nature of hard chrome layers. Postmachining induced significant superficial hardness increases in laser coatings, which was the main reason for good wear performance. Fatigue performance was strongly dependent on material pairs, presence of cladding defects, and applied loads.
A Risk Metric Assessment of Scenario-Based Market Risk Measures for Volatility and Risk Estimation: Evidence from Emerging Markets
Authors: Sitima Innocent , Hlatywayo Clifford K.
Published: March 2015

The study evaluated the sensitivity of the Value- at- Risk (VaR) and Expected Shortfalls (ES) with respect to portfolio allocation in emerging markets with an index portfolio of a developed market. This study utilised different models for VaR and ES techniques using various scenario-based models such as Covariance Methods, Historical Simulation and the GARCH (1, 1) for the predictive ability of these models in both relatively stable market conditions and extreme market conditions. The results showed that Expected Shortfall has less risk tolerance than VaR based on the same scenario-based market risk measures
Histamine Downregulates Aquaporin 5 in Human Nasal Epithelial Cells
Authors: Wang Weiwei , Wang Xiaolian , Ma Lan , Zhang Ruitao
Published: March 2015

Background

Aquaporin 5 (AQP5) is a water-specific channel protein. It is thought to be a key participant in fluid secretion and a rate-limiting barrier to the secretion seen during allergic inflammation. We sought to determine the effect of histamine on AQP5 expression in human nasal epithelial cells (HNEpC).

Methods

HNEpC cells were cultured with four concentrations of histamine in vitro. The phosphorylation of cyclic adenosine monophosphate-responsive element binding protein (CREB) at serine 133 and the AQP5 protein were measured by using immunocytochemistry and Western blotting. Real-time polymerase chain reaction was used to detect AQP5 messenger ribonucleic acid (mRNA).

Results

Concentration-dependent histamine induced-inhibition of CREB phosphorylation at serine 133 in HNEpC cells was observed, and AQP5 mRNA and protein were also downregulated in a concentration-dependent fashion.

Conclusion

Histamine downregulates AQP5 production in HNEpC cells by inhibiting CREB phosphorylation at serine 133.
Evaluation of Polymer Flooding Potential Based on Orthogonal Design and BP Artificial Neural Network
Authors: Wang Yanbin , Hou Jian , Cao Xulong , Wu Guanghuan , Wang Chuanfei
Published: March 2015

This paper has proposed a novel approach for evaluation of polymer flooding potential during oil reservoir development, which has integrated orthogonal design and BP artificial network.

This paper firstly divides the evaluated polymer flooding reservoir units into four styles using Weighted Euclidean Distance method. On the basic of unit sorting, we have generated predictive samples sets for polymer flooding potential with orthogonal design and reservoir simulation. In order to enhance the reliability and prediction ability of the polymer flooding network models, this paper has created a new orthogonal experiment design table to meet this study. It can cover the evaluated reservoir blocks but improve the extendibility of the network by enhancing training sample numbers. After that, Enhanced Oil Recovery(EOR) and Internal Rate of Return(IRR) predictive models of polymer flooding are constructed using BP artificial neural network method. At last, the paper has introduced two new concepts of applicability degree and risk degree to assess reservoir conditions for polymer flooding and implementation risk.

Taking technical, economic and risk factors into account, comprehensive potential evaluation was carried out with the predictive models of polymer flooding potential for part of reservoir blocks in Shengli oilfield in China.

The evaluation results have shown that the predictive models are of higher accuracy and better extendibility, which can satisfy the demands of engineering computation application.

Introduction

Polymer flooding has become one of the main enhanced oil recovery methods for inshore oilfields in China. At present, enhanced oil recovery techniques such as polymer flooding and chemical combination flooding, have been widely implemented in Daqing oilfield and Shengli oilfield in China and obtained great economic and social benefits (Chang et al., 2006; Sun,2006). But as a kind of tertiary recovery method for polymer flooding itself, there must be some certain risk for its field implementation owing to intricate reservoir conditions and high cost of chemical agent. And yet, under the situation of high international oil price, were the polymer flooding applied rationally and appropriately, it would still be able to gain better economic benefits. Therefore, it is very necessary to carry out the evaluation of polymer flooding potential including technical, economic and risk aspects so as to supply guidance for polymer flooding application to reduce investment risk and enhance economic benefits.
How Malfunctioning Completion Accessories Affect Well Performance Offshore Saudi Arabia
Authors: Al-Khanferi Mohammed Tariq , Bubshait Ahmed Khalid , Abd El-Fattah Mahmoud Mohamed , Al-Shabibi Hussain , Bawazir Mustafa Abdulrahman
Published: March 2015

To overcome horizontal well reservoir and production challenges, inflow control devices are adopted as the optimal completion method in many parts of the world. The main industry drivers for adopting inflow control device completions include balancing inflow along the well, delaying water and gas breakthrough, controlling water and sand production, and providing a cost-effective reservoir completion solution to meet the majority of the reservoir challenges. In offshore Saudi Arabia, inflow control devices have been used successfully in fulfilling these objectives. The downhole completion efficiency is evaluated using multiphase production logging tools.

Many completion accessories can be run with inflow control device completion strings, these include isolation packers, liner hangers, setting tools, end-of-completion string plugs and valves. All of these accessories may affect the well's production performance. New challenges arise when one of these accessories, such as the end-of-completion valve or isolating packers malfunction and develop a leak; thus, affecting the inflow control device completion performance. A major failure can result from such a malfunction, including fluid drainage from the toe section, sand production, early water breakthrough and water coning.

This paper presents two field examples in which multiphase production logging profiles of horizontal wells are used to evaluate the inflow control device completion performance and detect any completion-accessory malfunction. Multiple sensitivity simulation runs — supported by multiphase production logging results — facilitate optimizing the inflow control device completed well performance. This integrated approach is used to recommend solutions or remedial actions to overcome sub-optimal well completion performance. Also, the approach provides a comprehensive understanding of the reservoir results that should be considered in planning future completion and workover strategies.

Introduction

Hydrocarbon demands continue to drive production, particularly among assets in offshore reservoirs. Horizontal wells produce fluids by nonuniform inflow due to reservoir permeability/pressure variations along laterals, frictional effects along the wellbore, and sand production. The nonuniform inflow promotes early water/gas breakthrough. These wells are completed using inflow control devices (ICDs) with screens to optimize the well performance and overcome the main field challenges, namely formation damage during drilling by better cleanup processes, pressure loss due to heel-to-toe friction, and sand control.
Geomechanical Evaluation Enabled Successful Stimulation of a HPHT Tight Gas Reservoir in Western China
Authors: Zhang Hui , Qiu Kaibin , Fuller John , Yin Guoqing , Yuan Fang , Chen Sheng
Published: March 2015

Keshen reservoir is a deep, tight gas sandstone reservoir under high tectonic stress with reservoir pressure over 16,000 psi (110 MPa) and temperatures up to 165 °C. Development wells for this field are in excess of 6500m in true vertical depth. Stimulation is required to provide production rates that compensate for the high cost of drilling and completing wells. Hydraulic fracture design and execution must be optimal to ensure economic production.

To effectively stimulate a more than 200 m thick sandstone reservoir with consistently high performance, it is necessary to understand the mechanical behaviour of the reservoir, especially mechanical properties and in-situ stresses as the two control initiation and propagation of each hydraulic fracture. The mechanical behaviour is complicated by high tectonic stresses, significant compaction, and high overpressure.

To gain an in-depth understanding of the mechanical properties and in-situ stresses of Keshen reservoir, an integrated geomechanical evaluation was conducted. The evaluation used core from two wells, KS205 and KS207, and log data obtained from 15 wells including the wells with core evaluation in the field. A laboratory testing program to investigate the mechanical behavior of the reservoir sandstone under realistic in-situ stresses, pore pressures, and temperature was performed. The description of mechanical behavior obtained from the laboratory testing was used to calibrate and augment mechanical earth models (MEMs) constructed from well log data. The reliability of the completed MEMs was validated through comparison between wellbore stability predictions with observation of borehole failure from the borehole microresistivity image.

The geomechanics information was delivered to the stimulation engineering team. Hydraulic fracture design and execution was conducted based on this information. The outcome of hydraulic fracturing was very encouraging.

This study demonstrated that successful stimulation of tight reservoir in high pressure, high temperature relies on integrated geomechanical analysis.
Optimization of a High Fidelity Virtual Model of a Hydraulic Hoisting System for Real-Time Simulations
Authors: Pawlus Witold Pawel , Liland Fred , Nilsen Nicolai , Oydna Soren , Hovland Geir , Wroldsen Torstein Kurt
Published: March 2015

Nowadays, modeling and simulation software enhancing design and development of hydraulic-mechanical drilling machinery becomes increasingly popular in the offshore industry. The current work presents an efficient way to optimize large, high fidelity models of such equipment. First, a complex virtual model of the selected hoisting system is created and compared with the reference data logs recorded on a full-scale rig. Second, rules and guidelines for conversion of a complex model to a low fidelity model which could be simulated in a real-time (RT) environment are formulated.

Typically, a complex model of offshore machinery is suitable only for offline tests. Therefore, to perform RT simulations it is necessary to optimize it. The methodology presented in the current paper provides for interaction with a virtual model in real-time via a full-scale control hardware and software. This in turn allows to perform a hardware-in-the-loop (HIL) test and evaluate developed control systems as well as to verify if chosen control equipment meets the desired performance.

Simulation results prove that both high and low fidelity models yield comparable outcomes which correspond well to the reference real world rig measurements. It is concluded that to simplify a model it is important to determine how its particular components affect computational efficiency of the simulation hardware and to clearly understand functions of the considered machine.

The paper contributes in two areas. Primary - a high fidelity virtual model of an existing hoisting system is established. The simulated model is benchmarked against real measurements from the offshore drilling rig. Secondary - such a complex model is reduced and confirmed to be applicable for real-time HIL simulations. RT performance can be difficult to achieve even on modern computers due to the stiff nature of hydraulic-mechanical models and high demands on computational power.

Introduction

High level of technological sophistication, high price and small production numbers are the features that characterize the offshore equipment produced nowadays. According to Bak et al. (2011), manufacturers of offshore machinery are required to have a high level of experience and skills to design and develop their products due to the fact that normally it is not possible to construct prototypes to evaluate if a new design will work. Consequently, design engineers are constantly challenged to find the best possible trade-off between reliability, capacity, and cost of the produced equipment. Therefore, an increasing attention of the offshore industry is directed towards tools and methods that allow virtual prototyping and simulation of new designs which in turn makes it possible for engineers to test, redesign, adjust, and optimize a solution before it is manufactured.
Revitalisation of South Fawares Field Using Open Hole Multistage Completion Systems – A Pilot Project Case Study
Authors: Al-Najim Abdulaziz A , Al-Harbi Musaad S , Al-Rubaiyea Jamal A. , Al-Mutari Fawaz , Al-Ayyaf Emad A , Hadi Ahmed Abdul
Published: March 2015

Located in the Partitioned Neutral Zone between Kuwait and Saudi Arabia, the South Fawares field has been producing from the Lower Cretaceous Ratawi reservoir since 1956. Several conventional coiled tubing acidizing treatments have been performed to restore productivity from the Ratawi formation. However, due to the formation heterogeneity, limited zonal coverage and inconsistent acid distribution, these treatments resulted in limited improvements to productivity.

The objective of this study was to determine the most appropriate re-completion/stimulation technology that could achieve the following: Effectively and evenly stimulate the entire horizontal section,Benefit from the vast network of natural fractures within the formation matrix to further enhance production, andMaintain wellbore integrity.

This paper presents a successful pilot project implementing horizontal open hole multistage completion systems for the first time in the South Fawares field. Existing lateral sections drilled across the Ratawi formation in the South Fawares field were segmented into several stages and each stage was fracture acidized separately to achieve optimum acid placement and maximize the net stimulated reservoir volume.

The results show that effective wellbore isolation between stages coupled with efficient diversion of the stimulation fluid is key to improved well productivity. This paper highlights the planning, execution and challenges of the installation of these systems with comparisons of pre- and post-stimulation data and offset wells.

The success achieved from the first deployment of open hole multistage completion systems in the South Fawares field has opened new opportunities for reviving the productivity of additional depleted wells.

Introduction

The South Fawares field is situated in the Partitioned Neutral Zone (PNZ) between Kuwait and Saudi Arabia, (Fig. 1), where the natural assets are shared jointly under the Neutral Zone agreement signed in 1922. Since 1949, Saudi Arabian Chevron, a 100% owned subsidiary of Chevron, the Kuwait Gulf Oil Company and their predecessor companies have operated four oil fields in the onshore PNZ. The fields are Humma, South Fawares, South Umm Gudair and Wafra. In 2009, the 60-year agreement between Saudi Arabia and Chevron predecessor, Getty Oil Company was amended and extended for another 30 years. Under this agreement, Chevron operates Saudi Arabia's 50 percent interest and the Kuwait Gulf Oil Company operates Kuwait's 50 percent interest in the PNZ.
Remaining Exploration in the Southwest Malita Graben, Bonaparte, Australia
Authors: Tan H.K. , Jewett K. , Lorage A. , Amiribesheli S.
Published: March 2015

The Malita Graben, situated within the Bonaparte Basin, is highly under-explored relative to similar geologic settings along the North-West Shelf of Australia. The Mid-Jurassic Elang/Plover Formations have historically been the highly successful exploration target across this basin. However, with high reservoir temperatures and deep formation burial within the Malita Graben, reservoir degradation due to quartz overgrowths was considered a large risk at the Jurassic level. In 2011, D-1 and L-1 wells had drilled at the junction of the Sahul Syncline and Malita Graben to test the Elang/Plover play in the block WA. As a result, thick successions of high-quality Upper-Jurassic to Lower-Cretaceous 'Sandpiper' reservoir were intersected. Subsequent seismic, well log synthesis and reservoir characterisation studies have upgraded the potential of Sandpiper sandstones within the Malita Graben, which remain largely under-explored.

The strata penetrated by D-1 and L-1 wells provided key geological evidence to constrain the depositional model associated with the infilling stages of the Malita Graben. The wells intersected thick, homogeneous Late-Tithonian to Early-Berriasian quartzarenite units, encased in pelagic, deep-marine shales. 54m of conventional core was obtained in D-1 well, straddling the Tithonian-Berriasian boundary. The core is considered key as it refines biostratigraphic age dates, gives evidence for turbidite deposition in a deep-basin setting, and reveals a pronounced vertical heterogeneity in permeability readings. Correlating D-1 to L-1 wells suggests coeval stratigraphy, and thus possible lateral connectivity of a sand-rich submarine fan system in the vicinity of Block WA, and possibly in broader regions throughout the Malita depocenter.

The results of D-1 and L-1wells were significant in advancing the understanding of the Sandpiper sand distribution. The occurrence of thick Tithonian and Berriasian sands, which were not expected prior to drilling, opens opportunities for further review of the play in the Malita and Sahul depocenters. However lateral and vertical reservoir heterogeneity of the sands is both complex and challenging to apply to an exploration strategy across the Malita Graben. Modern seismic data may help enhance the understanding of the Sandpiper play in the area, but predicting clay mineralogy and its association with diagenetic processes on individual lobe sequences may remain elusive.

Introduction

The Malita Graben is a prominent depocentre within the Northern Bonaparte Basin and contains up to 10km of Mesozoic to Cenozoic sediments. Previous exploration in the area has been focused on the Middle Jurassic Elang-Plover play, but drilling has been largely restricted to structural highs adjacent to the main depocentres. Limited drilling has been undertaken within the Malita Graben, primarily because of reservoir quality risk sassociated with deeply buried, high temperature reservoirs.
Key Factors Differentiate the Success Rate of Coalbed Methane Pilots Outside of North America - Some Australian Experiences
Authors: Johnson, Jr. Raymond Leslie , Mazumder Saikat
Published: March 2015

Coalbed methane (CBM) has been considered a relatively mature unconventional gas resource in North America. In Australia, where the CBM or coal seam gas (CSG) industry is nearly two decades old, there have been successful and unsuccessful pilot projects and resources have been slower to develop after nearly twenty-five years since North American technologies were exported internationally. Thus, it is reasonable to believe that there are differences outside North America that have hindered CBM development in Australia.

Often CBM pilots owe their degree of success to one of three major factors: geologic or structural setting, reservoir properties, or completion strategies. Most pilot testing have been conducted either to characterize the production from a particular geo-domain associated with certain perceived geological risk and uncertainty or to estimate potential project reserves to a reasonable degree of accuracy. This need to reduce uncertainty is more pronounced in Australia based on the need to balance development decisions, tenure retention requirements, whilst minimising the risk for the upcoming development phase.

Often in hindsight, the opportunity to increase the chance of success for good areas or reduce the expenditures in poor areas was achievable through improved reservoir characterisation or better pilot planning. In some cases, the resource volumes are large, but the progression of resources to reserves has been less certainty based on challenges. In this paper we will highlight some key observations from several Australian CSG pilots that led to success or challenges for each case. The authors' goals are to identify key indicators, which if recognised earlier may have increased the rate of success or reduced unnecessary expenditures in these pilot areas.
Slickwater Chemistry Concerns and Field Water Management in Tight Gas
Authors: Langille David , Scheck Michael , Seligman Ben
Published: March 2015

The method of stimulation employed at the Shell Groundbirch asset in the Montney tight gas play is the limited-entry slickwater hydraulic fracture. The original fracturing water specification was a simple filtering requirement and an allowable range of salinity. Considering the associated health, safety, security, and environment (HSSE) perspectives, costs, and perceptions with sourcing and disposing of water related to hydraulic fracturing, determining a fracturing water specification became critical. This paper will describe a concise and pragmatic approach for determining a new fracturing water specification and water handling system aimed at recycling flowback and produced water, while using as little fresh water as possible.

This water specification case study is based on the industry considerations of hydraulic fracturing and water management, and their impacts on costs and the environment. This approach to determine a chemistry specification for slickwater hydraulic fracturing and handling considerations may be applied elsewhere to enable the optimization of sourcing and disposal, HSSE concerns, production impairment prevention, and cost reduction.

The process of determining the water chemistry specification assessed bacteria, formation damage, scale, and friction reduction performance. After a year of consultation and experimentation, an improved, but still simple fracturing water specification was established. Chemical use includes a scale inhibitor in addition to the on-the-fly fracturing fluids of a friction reducer, a surfactant, and a biocide. Scale inhibitor usage depends on pH and iron content. Coupled with water chemistry considerations, an integrated team initiated an intrafield water handling system that first recycles flowback or produced water and uses fresh water only when brine volumes are insufficient.

This paper will specifically address (1) a method to develop a water chemistry specification for slickwater fracturing, (2) a pragmatic means of forecasting water in tight gas developments, and (3) a means of integrating water chemistry and forecasting learning into application for pragmatic field development.

Introduction

Tight gas developments rely on hydraulic fracturing to produce gas at economically viable rates. One popular method of hydraulic fracturing is the limited-entry slickwater fracture treatment in which a number of perforation clusters are attempted to be simultaneously stimulated with a slickened water and proppant slurry in a number of stages throughout the wellbore. The implications of water in tight gas beyond hydraulic fracturing have been recognized at Shell Canada's Groundbirch development in the Montney play. Shell Canada's Groundbirch asset is located in Northeastern British Columbia, Canada, per Figure 1. The current land base consists of nearly 400 sections of Montney focused development of which about half are Shell's land held with Brion Energy, while the remainder are held jointly between Shell and other partners.
Permanent Downhole Gauges Selection for HPHT and Fractured Basement Reservoirs, Vietnam
Authors: Pham Hoanh Van , Green Christopher A. , Yapp Christopher , Le Thao Minh , Butt Andrew
Published: March 2015

CuuLong Joint Operating Company, Vietnam operates a number of HPHT and basement fractured reservoirs and has installed over 60 quartz or fiber optic permanent downhole gauges in development wells, since 2003. This paper reviews the selection process for the different type of gauges, gauge reliability and also details some of the considerations when assessing the relative cost advantage of each gauge type.

Equipment and material reliability has always been critical to success in the HPHT and fractured basement environment. As development wells target ever more challenging reservoirs, extreme testing and qualification processes are required to give reliable downhole sensors. This paper describes a methodology used by an Operator to address the significant challenges of selecting gauges for high temperature reservoir monitoring. The work details how the extensive qualification/testing process was successfully applied to select suitable gauges. Initially, after selecting quartz gauges the first deployment of an optical gauge system took place offshore Vietnam in February 2009. To date a total of 20 fiber optic gauges have been installed on different platforms in various reservoirs and when successfully installed have achieved a 100% success rate.

Four major areas were addressed using this methodology, which are necessary in order to ensure success:Establish applicable standards appropriate optical sensing technology to which components should comply, in order to qualify for selection.Determining the reliability of electronic gauge systems in the specified high temperature reservoirs environment.Develop an effective monitoring and optimization process that considers all possible scenarios, in order to properly assess the cost-benefit of the proposed system.Continually review and improve the system based on available data and analyses.

Application of this methodology has led to a 100% success rate for recently installed gauges and application of this system, developed over the past 10 years, should help other operators world-wide achieve similar success rates in comparable, 'extreme' reservoir monitoring environments.
An Evaluation of Various Perforating Designs Performance in Reducing Near Wellbore Friction during Fracturing
Authors: Al-Momin Ali Mansour , Al-Saihati Ali Hussein
Published: March 2015

Establishing connectivity with the reservoir in a cased-hole cemented completion is a crucial parameter for the success of fracturing operations. Numerous fracture stimulation treatments have failed due to the failure to initiate the fracture or to place enough proppant along the hydraulically created fracture due to an early screen-out caused by improper perforating design. This problem becomes more significant in the case of unconventional resources exploration and development as these resources inherently require a high treatment pressure coupled with a high fracturing gradient. Therefore, a well-engineered perforating design is regarded as the first challenge to be overcome to ensure the success of a fracturing treatment.

This paper presents a comparative study among different perforating guns by different service providers with different sizes in terms of reducing the near-wellbore pressure loss during fracturing treatment. Moreover, various design parameters such as perforation phasing, density and perforating interval were evaluated for several gas wells completed with proponent fracture in a giant field in Saudi Arabia. The comparison is based upon analyzing the step-down rate tests and quantifying the contribution of pressure loss due to entry friction to the total friction during the stimulation. The magnitude of the treating pressure for various designs during the main fracturing treatments was also examined. Reservoirs investigated include tight sand and unconventional gas bearing formations. Different techniques to mitigate or reduce excessive near-wellbore friction are also presented.
Planning infill drilling and workover programmes based on reservoir-oriented production logging surveys
Authors: Aslanyan Arthur , Aslanyan Irina , Karantharath Radhakrishnan , Matveev Sergey , Skutin Vasilii , Garnyshev Marat , Bevillon Damien , Mehrotra Nagendra , Suarez Nelson
Published: March 2015

Wellbore fluid flow profiles in both producers and injectors tend to change over time due to preferential depletion, formation damage, cross-flow, channelling or tubing or casing leaks. These changes can result in excess water production through channelling, coning, non-uniform water breakthrough (fingering) or out-of-zone injection – all leading to uneven flow, pressure and sweep profiles. Ignoring these complications can result in missing key points on reservoir behaviour, selecting wrong units for a 3D full-field flow model or misleading redevelopment planning. Therefore, it would be logical to check for changes in flow geometry before embarking on costly workovers, recompletion or infill drilling programs.

This paper compares and integrates the results of conventional Production Logging Tool (PLT) surveys that use spinners and multiphase sensors with those acquired by reservoir-oriented production logging surveys employing a combination of Spectral Noise Logging (SNL) [1,2] and High Precision Temperature (HPT) Logging [3–5]. PLT and HPT-SNL produce similar results when wellbore and completion conditions are good but they may differ dramatically in cases of non-uniform formation damage, channelling behind pipe or plugging of perforations by scale. Generally, HPT-SNL would assess the flow geometry and invaded zones of the reservoir while PLT would point out where fluid enters or leaves the wellbore or tubing.

The paper provides case studies from a mature offshore waterflooded field producing a mix of oil, gas, formation water and injection seawater, which complicates the identification of flow geometry and invasion zones and represents a challenge for reservoir engineers in developing proper drilling or workover programmes to target residual reserves [6, 7]. The HPT-SNL-PNL surveys and further studies described here led to successful workovers and drilling. The redevelopment results can be easily assessed by decline curve analysis.

Introduction

Since 2007, Dubai Petroleum Establishment (DPE) has performed more than 150 integrated PLT-HPT-SNL surveys to monitor vertical wellbore injection and production profiles that resulted in valuable and often surprising findings including unexpected water breakthrough intervals, bypassed oil zones and layers and water channelling behind casing in producers and injectors. These findings, in turn, led to a better understanding of how water propagated through reservoir from injectors to producers and were used to calibrate a 3D full-field flow model and identify optimum infill drilling locations for the redevelopment of the highly fractured crestal area of the field.
Improved Employee Retention Through Active Engagement and Focused Action
Authors: Raj Reuben D. , Zaid Elfarina
Published: March 2015

Extended Abstract

Introduction

The company operates a Technology Center to manage new product development, manufacturing, supply chain and product-sustaining activities on the island of Singapore. The Technology Center has an average of 950 employees who are divided into two groups i.e., Exempt and Non-Exempt. The Non-Exempt employees are eligible for overtime pay whilst the Exempt population, made up mostly of office-based staff, are not eligible for overtime. The ratio of Non-Exempt to Exempt staff in this Technology Center averages about 60:40 for the last 5 years.

Since 2009, one of the main challenges faced by the Technology Center in Singapore was the high turnover of employees, especially in the Exempt group.

This extended abstract will describe best practices and lessons learned in the Singapore Technology Center to improve employee retention in the last 2 years.

Based on surveys and feedback sessions, lifestyle and career barriers were regarded as some of the main factors that impacted employee retention.

Various initiatives were conceived and implemented to engage the target population, facilitate active discussion, and improve employee morale and satisfaction at work through focused action.
Seabed Acquisition Systems: How Broad is the Broadband?
Authors: Kumar Subodh , Foo Low Cheng , Chandola Sandeep Kumar , El Kady Nabil , Bin Zawawi Mohamad Zabuddin , Ghazali Faizan Akasyah
Published: March 2015

Seabed acquisition is expected to deliver broadband seismic data by using a combination of pressure and particle motion or acceleration measurements to eliminate the free surface ghost. In this paper, we have investigated the frequency bandwidth delivered by different seabed acquisition systems, i.e. two component ocean bottom cable (2C-OBC), four component ocean bottom cable (4C-OBC) and four component ocean bottom node (4C-OBN) systems on the low frequency side, under different geological settings and acquisition environments. The study was carried out by analysing the effect of total system (source, receiver and recording instrument) response and frequency bandwidth for different types of seabed acquisition systems and sensors. The analysis shows that after optimal compensation for total system response, different seabed systems and sensors deliver comparable low freaquency signal in the band of 2–5 Hz given the variations in the local seabed conditions.

Introduction

The recent emergence of towed streamer based broadband seismic technologies poses an interesting question, "how broad really is the broadband data delivered by various seabed acquisition systems, especially at the low frequency end?" During the last few years, PETRONAS has acquired more than 1,200 sq. km. of 3D and 540 LKM of 2D seabed seismic data using 2C and 4C acquisition technologies. Majority of the data were acquired using OBC technology and different acquisition systems with a limited amount of data acquired using OBN technology. The main objectives of the study were to analyse:The effect of total system (source, receiver and recording instrument) response on the signal bandwidth and the effect of source-receiver notchesThe frequency bandwidth delivered by different seabed acquisition systems and the conventional towed streamer system.

The effect of source volume on the bandwidth, if any, was not analyzed in this study.

One of the main benefits of seabed acquisition is that it delivers broadband and wide azimuth seismic data. The high frequencies are important for improving the resolution, while the low frequencies provide the opportunity for better seismic inversion and well ties. The seabed acquisition improves the signal bandwidth by enhancing both high and low frequency ends of the spectrum. It uses co-located measurements of two vertical components (P and Z) which help to remove the free surface ghost (Fig 1) and improve the overall signal bandwidth.
LULA Exercise: Testing the oil spill response to a deep sea blow-out, with a unique combination of surface and subsea response techniques
Authors: Michel Cedric , Cazes Laurent , Eygun Christiane , Page-Jones Lindsay , Huet Jean-Yves
Published: March 2015

To test the improved blow-out response capabilities implemented following the Deep Water Horizon accident which took place in 2010 in the Gulf of Mexico, Total E&P Angola (The Affiliate) was chosen by Total H.Q. (The Company) to organize and run a large exercise. The objective was to check the ability to efficiently define, implement and manage the response to a major oil spill resulting from a subsea blow-out, including the mobilization of a new Sub Sea Dispersant Injection device – SSDI kit from Oil Spill response Ltd (OSRL-Norway). After one year and a half of preparation in collaboration with the Angolan Authorities, the exercise took place from the 13th to the 15th November 2013, based on a blow-out scenario of 50,000 bopd. In Luanda, the Affiliate emergency response organization was mobilized together with the Angola National Incident Command Team, as well as the Company Crisis Team in Paris.

Various monitoring and modeling techniques were compared, using an authorized crude oil discharge at sea : e.g. direct observations from helicopter, OSRL aircraft, new Observation Balloon, slick tracking with drifters and interpreted RADAR satellite imagery, 5 days/3D modeling of oil fate and behavior using the modeling SPILL WATCH service. Overall results obtained proved consistent despite of the fact that modeling of surface currents is still not fully reliable.

The SSDI kit was shipped by plane from Norway and successfully tested in deep offshore. On the surface, dispersion, containment and recovery operations were implemented.

The onshore strategy encompassed protection of sensitive sites, shoreline clean-up, oily waste and oiled wildlife management, as well as liaising with local communities and claims management. To sustain the response, complex logistical support was also planned.

Owing to the ambitious objectives, variety of operations, level of mobilization in Angola and in France, implication of the Angolan authorities and considering over 500 persons were safely involved in the operations, LULA is a unique exercise and proved to be a great success. Lessons learnt will serve to improve blow-out response capability, but also oil spill response and emergency management capabilities not only within the Company, but also for the benefit of other oil operators, support companies and the National Authorities.
Bream Field (Phase 4) - EOR and Late Field Life Management
Authors: Snow Thomas Milton , Mckay Ian , Irwin Drew Douglas
Published: March 2015

Bream Field, in Australia's Gippsland Basin, was originally developed in 1987 as a thin oil column development with gas cap re-injection. A satellite platform was installed in 1996 to capture resource not reachable from the original platform. After achieving 68% recovery, oil rates had fallen to the point that gas cap blowdown was commenced. Given the extremely strong natural pressure support seen in the Gippsland basin, a controlled blowdown was carried out to maximize oil recovery during gas export. As the water level approached the top of the structure, an assessment was carried out to determine the best use of the field infrastructure.

The result of this effort was a decision to utilize the field for gas storage while simultaneously achieving enhanced recovery. By refilling the Bream reservoir with dry gas from the Longford gas plant during the summer months, high liquid yield fields are able to be produced consistently throughout the year. Additionally, Bream gas deliverability capacity is increased in the high gas demand periods. As the dry gas moves through the reservoir, it contacts both residual oil and rich gas, becoming re-saturated with gas liquids. When this gas is re-produced, it will yield more liquids, raising the overall recovery of the oil by approximately 1%. Re-injection into the Bream reservoir began in 2013 and is proceeding as planned.

This paper will discuss the history of the Bream development, highlighting the analysis and planning that led to the recently implemented project. The management of this field demonstrates a number of techniques for maximizing hydrocarbon recovery over the life of a field, as well as considerations for maximizing economic value of the infrastructure.

Background

Bream Field, in the southwestern part of the Gippsland Basin (Australia), was originally discovered in 1969 and first developed in 1987. It is produced by the Gippsland Basin Joint Venture (between Esso Australia Resources Pty Ltd and BHPBilliton Petroleum (Bass Strait) Pty Ltd), with EARPL as the operator. GBJV offshore infrastructure includes 19 platforms, 4 subsea installations, and a network of pipelines feeding the Longford Gas Plant (see Figure 1). Approximately 98% of the production from the basin has come from the GBJV, since start-up in 1969. Bream Field and its development have been described in several publications, including:Shaw (Shaw, 1991) described the mechanical aspects of the initial horizontal drilling program;Titus (Titus, 1997) described the design and installation of a second satellite platform;McKerron et. al. (McKerron, 1998) described the development process and results from that second platform;Fish and Zajdlewicz (Fish, 2004) described the strategy for maximizing recovery during blowdown.

The Bream development history, along with the forward plan described here, provide an interesting case study that demonstrates how available technology and the market demands drive development decisions.