bluuebunny/crossref_metadata_2025 huggingface dataset:
Identifying and Assessing Productivity in CO2 Bearing Gas Zones Using Wireline Logging and Testing Data
Authors: Courel Romain , Cartwright Tony , Herries Rob , Gok Ihsan Murat , Millot Pascal
Published: February 2015

One of the common challenges in the Malay-ThoChuBasin of Vietnam is that hydrocarbon accumulations consist of multiple layersand compartments (tens to hundreds) with variable reservoir quality, hydrocarbon types and CO2 contents. Understanding the CO2 distribution before committing to a productiontest is essential. Neither mud logging nor Logging While Drilling (LWD) nor traditionalwireline measurements are able to quantify CO2 content. An efficient method toquantify CO2 content is to usenear infrared equipment mounted along the Wireline Formation Tester (WFT) flowlinedownhole. This approach can then be validated against laboratory measurements. Permeability is a critical parameterwhen dealing with heterogeneous reservoirs management and well performance. Thecontinuous permeability measurement from Nuclear Magnetic Resonance (NMR) loggingcan be optimised if calibration information is available, particularly from intervalpressure transient tests (IPTT) obtained from "Mini-DST" packer formation testingof selected flow units, and even from pumpouts performed for downhole fluidanalysis and sampling. The calibrated continuous permeability curve from theNMR log and hydrocarbon compositions from the WFT sensor are then used to design conventional drillstem testing, and can also be used to model deliverability of reservoirs nottested by a conventional DST. Three case studies are presented. Thefirst is a well that encountered multiple reservoirs with variable CO2 content. Downhole measurements using the WFT sensor were acquired from every reservoir>2m thick with PVT samples obtained from four reservoirs for calibration. Subsequent comparison and delumping of the downhole compositions produced areliable estimate of CO2 content and basic PVT parameters in all significantreservoir sands. The second case study demonstratesapplication of an IPTT obtained from a dual-packer "miniDST" on a thin, highCO2 hydrocarbon-bearing sand to calibrate the NMR continuous permeability curve. This was then used to model the deliverability of a thick, low CO2 reservoirwithout the need for a full production DST. The third case studyshows anintegration of downhole compositional measurements, NMR permeabilitycalibration on wireline packer IPTT and comparison to an actual production DSTfrom one of the reservoir intervals.
Unlock Tight Gas Reserves in South China Sea by a Revolutionary Formation Tester
Authors: Hongjun Yang , Shusheng Guo , Jun Cai , ChengGang Xian , Jichao Chen
Published: February 2015

As interest grows in formations with permeability ranging from tight (<1.0 md) to ultralow <0.1 md), formation testing and conducting drill stem tests (DSTs) become increasingly challenging and more costly. Formation testing using conventional probes has low success rates for pressure surveys and sample collection, long pumping times, and poor data quality that cause difficulty in fluid identification because of incomplete cleanup of filtrate. DSTs are often unsuccessful without sufficient inputs of permeability and fluid properties for optimization of testing plan. This paper presents case studies of a revolutionary new 3D radial probe that makes effective evaluation possible for unlocking tight gas reservoirs in the South China Sea.

The tight gas formations have poor borehole condition for conventional probe sealing and testing. A total of 25 attempts by two different conventional probes fail to seal. However, three stations for the 3D radial probe took less than 4 hours per station to successfully collect PVT-quality samples. Fast cleanup to flow pure formation fluids enabled better accuracy in real-time fluid identification, sampling assurance, and compositional analysis including CO2. Transient analysis indicated that all stations have <0.1-md/cp effective mobilities, with the lowest at 0.03 md/cp. Production prediction was conducted to assess the natural productivity. Comparison with DST results from neighboring wells show that this prediction has acceptable accuracy and is sufficient for crucial decision making. This enables the operator to avoid unnecessary DST stations and ensure optimal completion and well testing designs.

Performance was compared against conventional modules. The advantages of the 3D radial probe over elliptical probes and dual-packer module in this kind of tight gas reservoirs are obvious and significant, with better efficiency, quality and operability such as applicable differential pressure, sealing capability, minimum storage, no exposure to borehole mud, and less sticking and plugging probabilities. Numerical modeling of an immiscible water-gas system with representative borehole conditions and reservoir properties of tight gas formations was conducted to investigate flow and pressure transient behaviors for operation optimization. Initial results of the simulations will be briefly discussed in this paper.
Applications and Performance of Trenching Technologies in Asia-Pacific
Authors: Brunning P. , Machin J.
Published: February 2015

Description ofproposed paper:

Burial ofsubmarine pipelines and cables is standard practice in offshore oil and gas regionswhere potentially damaging threats such as interaction with fishing gear anddragged anchors are high. The requirement to bury pipelines in Asia-Pacific hasnot had the same imperative as the North Sea for example but this region is nowseeing a growing demand for pipeline burial to increase mechanical protectionand stability. Performance benchmarks for most trenching systems are based onthe seabed soils typically found in the North Sea and consequently do notinclude the unusual carbonate rich seabed sediments that are prevalent in theAsia-Pacific region which are often cemented and pose a significant challenge to trenching.

Application:

Trenching isconsidered an activity with significant risk so it is particularly important toselect the correct tool for the field conditions and to establish realisticperformance criteria based on regional experience in the prevailing seabedsoils, including carbonate rich sediments. This paper addressesthe primary differences that exist in seabed sediments and trenching conditionsbetween Asia-Pacific and other regions and show how these dissimilaritiesimpact on the choice of burial equipmentand tool performance. Results, Observations, and Conclusions:A state of theart review of trenching methods and technologies is presented. Trenching casestudies from Australia and Asia are presented which highlight the challenges ofdesigning an appropriate protection and burial strategy for this region and providesindications of actual performance that can be expected across the range ofseabed conditions typically found in the Asia-Pacific region. This includesdata for trenching in harder cemented soils to help fill the gaps associatedwith performance predictions in carbonate sediments. Significance of

Subject Matter:

The significanceof this proposal paper can be summarised as follows:It provide a reference point onwhich to plan trenching work in Asia-Pacific region,It addresses the knowledge gapsassociated with the relative inexperience of trenching in Asia-Pacific regionPerformance benchmarking is extendedto include the carbonate rich and cemented sediments.
Optimized Platform Placement to Cover All Geological Targets in Baronia Field
Authors: Sofian M. Anas , Leuranguer Christophe , Bt Musiran Noor Farahana , Saifuddin Afiqah Fathiah Ahmad , Wong Thomas , Kardani Ilen
Published: February 2015

Platform placement and sizing are critical steps for enabling subsequent operations such as well construction, logistics, and facilities installation to be performed efficiently and safely. This paper introduces the most economical yet efficient solution for a PETRONAS enhanced oil recovery (EOR) project in which 25 wells were to be drilled in Baronia field, offshore of Sarawak, Malaysia. Collaborative teamwork from drilling, reservoir, facility, geology, and production groups was required to develop the best solutions to minimize construction work, simplify well trajectories, and utilize all available resources to help minimize the overall budget.

In addition, this paper evaluates the drillability of each well based on available drilling technologies and rig capabilities in the market.

During the initial design stage, all 25 wells were planned to be drilled from two new wellhead platforms (WHP) to intercept all geological targets. Major well collision problems were encountered against adjacent wells in the congested Baronia field; however, after several iterations of surface nudging and slots designation, all wells were drillable, with a total footage of 227,527.1 ft drilled.

The first iteration was performed by placing one new single WHP at an optimized location and using spare slots and sidetracking from an existing platform. This optimized design reduced/saved 39,868.61 ft compared to the initial stage and eliminated the requirement for another new platform. The second iteration was performed by shifting the new WHP 300 ft closer to the production platform to enable bridge linking and help reduce construction work on the pipelines. The total footage to be drilled from this location was reduced again by 3,622.63 ft. Finally, the setup was further optimized by equipping the new platform with splitter wells, which reduced the number of conductor pipes required without decreasing the number of wells to be drilled.

Overall, the platform placement and sizing optimizations saved millions of dollars in the planning stage by eliminating one platform, decreasing drilling footage, minimizing construction work, and helping reduce health, safety, and environment risks.
Improved Zonal Isolation in High-Temperature Offshore Wells with an Advanced Lightweight Cement Design - Gulf of Thailand Case Histories
Authors: Brandl Andreas , Valentino Vincentius , Fauchille Guillaume , Syed Haidher , Dean Greg , Stanley Rick , Rivera Nemboy Nemesio
Published: February 2015

The Gulf of Thailand is characterized by shallow-water wells that are hot and deviated, with low fracture gradients and bottomhole static temperatures of 450°F (and some wells approaching 520°F). Drilling depths average 12,000 ft measured depth (9,000 ft vertical) and fast drilling practices are used for slimhole monobore completions, resulting in daily cementing jobs from each of the offshore rigs. Many jobs are executed in batch mode and are performed offline on the production deck under the rig floor. As a consequence these fast-paced, streamlined, and simultaneous offshore activities require a high degree of rig integration as well as logistically and operationally simple high-performance cementing systems to avoid expensive rig delays. The performance demands on the cement slurries include low density, uncomplicated on-the-fly mixing, low fluid loss, gas invasion control, and stability under the very hot wellbore conditions.

This paper will present an advanced lightweight seawater-based cementing concept using a single cement blend with only 3 to 4 primary liquid additives (including a multifunctional polymer) to adjust all primary cement jobs for the entire wellbore. A sophisticated lab testing program (such as analyzing slurry gas invasion) was conducted for the innovative cementing concept according to the required demands on cement slurry design and the given harsh wellbore conditions in the Gulf of Thailand. Tests revealed that the developed cementing systems meet all operator and well requirements despite their relative low densities of 13.3 to 14.0 ppg with high water content.

The advanced lightweight cementing design was successfully pumped in 311 Thailand offshore wells during 2012, and its performance was directly compared to previous cementing systems used in more than 1,000 wells in the same fields from 2009 to 2012. Lab test results, pre-job planning, cement job execution and cement bond logs are evaluated and discussed. The case histories conclude that the advanced lightweight cement design significantly improved the quality of zonal isolation in wellbores. Valuable design-effect relationship elements found in this study (such as the impact of the multi-functional polymer on slurry stability and gas control) will be discussed for applications on other upcoming and challenging drilling projects in Asia.
Importance of Thermal/Stress Loading Analysis for Tubulars in HPHT Wells
Authors: Shahreyar Noman , Finley Douglas
Published: February 2015

The upstream oil and gas industry is experiencing increased interest in exploration and production from the more complex, hostile, and deeper geologic horizons that are classified as high-pressure, high-temperature (HPHT) reservoirs. Well completion planning and design is becoming increasingly more critical and challenging because of the uncertainty that typically is experienced from the high pressure and temperature changes that can occur in operational scenarios during the well's lifecycle.

The cost of a typical tubing completion equipment usually represents 15 to 25% of overall well cost. High operating temperatures and pressures cause significant pipe movement and high axial loads at the packer and tubing during the well operation. For wells where design margins can be slim, a detailed and robust stress-loading analysis and the aid of modern thermal-and-stress- analysis software can balance tubular equipment design versus risk. This approach provides savings on tubular cost by optimizing the tubing design so that it meets the company's integrity standards without being overdesigned.

This paper discusses an engineering design methodology that can be followed for tubular equipment sizing and selection for complex wells. A typical list of reservoir and well parameters that are required to set up the well model for the thermal and stress loading analysis is presented. Importance of estimated thermal simulation is highlighted for tubular selection and design. A full integrity analysis for well casing and tubing design integrity will be performed for a complex, deep-water, high-rate, HPHT example well. The analysis will cover various anticipated operating loads during the life of the well and will include the effects of stimulation, production, and EOR flooding. Results are presented showing changes in temperature and pressures during well operating scenarios and impact of temperature changes on tubulars stress loading. Sensitivity analysis is then performed with applied landing forces on the completion for further discussion on limitations on well operating conditions during well life cycle.
Utilising Aerogel in Effective Oil Spill Cleanup and Recovery
Authors: Singh Apoorv
Published: February 2015

Oil spill is currently a burning issue. The damage to the environment caused by an oil spill of any size demands immediate cleanup. The issue of Arctic drilling is of global concern and the industry must be equipped to tackle the problem of oil spill, if any. Current oil spill cleanup methods include booms, skimmers, and centrifuges. However, these containment methods have not been successful as nearly 60,000 barrels of oil are released into the water each day, and their efficiency to collect the leaked oil is too low. The paper presents an approach to solve this problem by use of porous material that not only absorb oil effectively but also provide a way to recover the spilled oil.

Aerogel is such a synthetic porous material derived from a gel, in which the liquid component of the gel has been replaced with a gas. The product formed is a solid with very low density. A form of this Aerogel is made by mixing clay with a polymer and water in a blender. The mixture is then freeze-dried, air fills the gaps left by the loss of water, and the resulting material is ultra- lightweight sponge, comprising of about 96% air. The Aerogels are synthesized by a NH4OH catalyzed reaction and are found to be hydrophobic. Treating oil and salt-water mixtures with the aerogel at an oil to aerogel ratio of 3.5 showed that all CF3-aerogels efficiently separated oil from water, absorbing oil as much as 237 times of their weight. The present hurdle with the industrial application of Aerogel is its economical feasibility which can surely be overcome in upcoming years with the recent advancements in technologies. Future oil spills can be very effectively tackled by the use of Aerogels or other porous materials as Oil Spill Cleanup agents.
Water Injection in Brown Field: Never Too Late
Authors: Baruah Bikram M. , Chan Keng Seng
Published: February 2015

It has been observed that in many brownfields across the world having 25-30 years of production history, waterinjection projects were not undertaken to maintain pressure in earlier stage ofthe fields' life while the average reservoir pressure depleted well below thebubble point pressure. Is it too late to initiate water injection? Is ittechno-economically justifiable? This paper attempts to explore thesequestions. It may be uneconomical and ineffective to carry out full field water flooding project in a marginal brown field. However, selective water injection to boost up pressure in carefully selected pockets ofthe reservoir might help gain significant incremental oil production. Torestore the reservoir pressure back to the original bubble-point pressure might be unnecessary anduneconomical. However, it might be sufficient to pressure up the reservoir tocritical gas saturation pressure, enough to arrest the excessive gas productionhelping more oil to produce. In our case studies, we studied the J-sandreservoir of the Seligi Field, the largest oilfield in Peninsular Malaysia, located approximately 280 kilometers off the eastcoast of Peninsular Malaysia, at a water depth of about 70 meters (230 feet). In this large (8km × 12 km) maturing offshore reservoir (30 year of production history)comprising multiple interdependent closures with relatively thin oil columnsand large gas caps, contains roughly 1.823 BSTB STOIIP. The reservoircommunicates with nine neighboring producing fields via a common regional aquiferencompassing an area of more than 7000 square kilometers. As of Q4 2011, the field produced 532 MSTBor yielded a recovery of 29%. Gas injection was initiatedin some parts of thefield. However, water injection has not been commenced. Simulation studiesestimated that no further activity scenario would yield only an additional 18MSTB (~ 1% Recovery) by year 2021. However, initiating selective waterinjection even at such a late stage can significantly boost the oil recovery byabout 5%, making it a viable commercial proposition.
Infield Transportation of High Content CO2 Fluids
Authors: Condat C Taravel , Denniel S
Published: February 2015

There is a strong demand in the subsea oil and gas industry for cost effective solutions for transportation of highly corrosive fluids. In particular, high concentrations of CO2 are prevalent in both injection fluids (up to 90%) to enhance the oil recovery process and in some production fluids (up to 75%). This paper will present the work carried out to qualify reeled rigid and flexible pipes for transportation of fluids containing very high pressure of CO2.

For flexible pipes, this work concentrated on qualification of several thermoplastic materials used for pressure sheathes and stainless steel materials used for inner carcasses, and it covers application as high as 90°C/600bar/100%CO2. Qualification of stainless steels carcasses for production applications containing high level of CO2 and chlorides has also been conducted.

For rigid pipe applications, Corrosion Resistant Alloy (CRA) can be used either as the linepipe material or as a metallurgicaly bonded liner to the inside of a carbon steel or stainless steel linepipe. Mechanically Lined Pipe (MLP) is a cost effective alternative to metallurgical bonding which has been qualified for installation by reel lay method at atmospheric pressure for static flowline and dynamic riser application. The qualification process complied with DNV "Qualification of New Technologies".
Measured Wave Spectra Offshore Sabah & Sarawak, Malaysia
Authors: Amurol Jamal Sharizal , Ewans Kevin , Sheikh Rizwan
Published: February 2015

The use of wave spectra in offshore engineering is a key ingredient of the design process. Empirical formulations of wave spectra are used extensively in offshore engineering. These spectra describe a smooth spectral density that represents the wave energy density for a given wave frequency and direction. Two of the most commonly used spectral formulations are forms of the Pierson Moskowitz (PM) and JONSWAP formulations, which describe fully develop and fetch-limited seas, respectively. An interesting result of the JONSWAP study is that a wave spectrum continues to evolve with increasing fetch or duration without actually becoming fully developed.

The JONSWAP spectrum, which was derived from fetch-limited measurements made in the North Sea, has a mean shape represented with a peak enhancement factor, [[Unsupported Character - Symbol Font ]], equal to 3.3, which in engineering applications is often adopted on the assumption that this spectral shape is valid for all locations. This is primarily because historically there has been insufficient measured raw wave data to enable the characterization of basin specific wave spectra. In reality, the wind field is rarely sufficiently steady or spatially homogeneous for sea states to be fetch-limited, and as a result the mean JONSWAP formulation may not be suitable to describe wave energy densities for design purposes.

This paper presents the results of a study of measured wave spectra offshore Sabah and Sarawak, Malaysia. The study is the first systematic analysis of raw wave data to determine the shape of the wave spectrum offshore NW Borneo. The characteristics of these measured spectra are discussed here together with a comparison to the JONSWAP formulation.
Condition-Based Pigging for Pipeline Network
Authors: Zainal Abidin S. , Norman A. , Khairil Hing A. , Juzaimi N. , Ismail M. , Alias M.
Published: February 2015

Pigging operation is primarily conducted for flow assurance and integrity of the pipeline. It will ensure maximum throughput and minimize internal pipeline wall corrosion by removing debris, asphaltene, sulfate reducing bacteria (SRB) and other impurities from the pipeline. Currently at PMO, pigging operation is conducted per time-based as required by pipeline's Corrosion Management Plan (CMP). The pigging frequency will be revised should there are changes to the amount of water holdup inside the pipeline. Since there is no reliable way to predict how much water holdup and heavies will deposit, pigging frequency can be optimized only by learning system behavior. Once the system behavior is better understood, the condition-based pigging frequency can be optimized.

Mathematical study utilizing numerical method analysis was performed by doing mass balance analysis of the recorded pipeline discharge and landing flowrate. Daily flowrate discrepancies between inlet and outlet flow were plotted. Cumulative flowrate discrepancies were calculated via a numerical method analysis technique. Data delay was also considered based on pig traveling time and/or fluid velocity in pipeline. Pipeline simulation model was developed using iCON with OLGAS 3Phase flow correlation to validate liquid hold up findings from numerical analysis. Other relevant parameters and profiles of the pipelines are also calculated such as pressure, temperature, velocity and flow regime. iCON is a steady state and dynamic simulation software widely used in PETRONAS with a variety of applications for upstream and downstream businesses.

The study has realized accurate approach to quantify the amount of liquid hold-up volume as well as other operating parameters such as velocity, pressure profile, flow regime and temperature to identify the pigging requirements for the pipelines for Tapis-P to TCOT pipeline. PMO pipeline engineer optimized pigging activities by switching from time-based to condition-based pigging. Several case studies were demonstrated in this paper to show that the modeling techniques applied matched liquid holdup accumulated at receiving terminal.
Successful Development and Application of Sand Transport Correlation for Upstream Oil & Gas Application
Authors: Zamberi M.S.A. , Shaffee S. , Moh C.K. , Jadid M. , Johar Z. , Wong C.Y.
Published: February 2015

Sand production related problems are common in E&P operation. Understanding and predicting sand transport is one of the key elements to develop an effective sand management strategy.

From a review conducted, it was found that majority of the sand transport prediction correlations available in the literature were developed through experimental conditions that were closer towards the mineral and mining industries. This paper discusses the development of an enhanced critical sand transport velocity correlation through experimental campaign focusing on improving the correlation for upstream oil and gas application especially on the effect of sand concentration, fluid viscosity and flow inclination angle. Comparison with several third party experimental data is provided, showing the improved accuracy of the developed correlation in conditions closer to upstream oil and gas operation.

The experimental campaign consist of flow loop experiments at selected sand (concentration <<1%vol-vol, size up to 200 micron, angular shape) and fluid conditions (viscosity between 1 to 10cP), and at different inclination angles. Using the experimental results, a sand transport correlation was enhanced which showed much improved accuracy compared to existing sand transport correlations (average deviations of the enhanced and existing correlations are ±7% and 40% respectively). The enhanced correlation was also able to predict accurately (less than 10% deviation) of third party experimental data. The correlation is also able to qualitatively match sand monitoring data from several operating wells.

Finally, application of the correlation in developing an effective sand management strategy for high-sand-producing wells in Malaysia, through integration with a sand erosion prediction tool is discussed whereby the current field practice in surface sand management was reassessed resulting to incremental hydrocarbon production.
How to Increase Recovery of Hydrocarbons Utilizing Subsea Processing Technology
Authors: Marjohan Rudisham
Published: February 2015

As demand for oil escalates and resources from the relatively simple onshore and shallow water fields become relentlessly depleted, oil companies are compelled to focus on more remote, complicated and deeper water reserves. At the same time, emerging technologies to increase recovery and extend the life of brownfield developments often requires moving this equipment to the seabed due to topside space, capacity and integrity constraints.

These technological challenges are now being met head-on with subsea processing and the need to provide an increased recovery factor to justify the large investment made. Not only does subsea processing become an enabler for producing from these challenging environments, it also frees up space on the topsides while allowing expansions to be implemented on the seabed, with the additional benefit of offering significant cost saving possibilities. Notably, subsea boosting has demonstrated added value for increased hydrocarbon recovery through several commercial installations since 1995.

This technical presentation will focus on increasing recovery of oil and gas by implementation of subsea processing techniques and in particular, subsea boosting. An overview of the different applications of subsea boosting systems will be given. This will cover options that include subsea single-phase and multiphase hydrocarbon boosting, subsea seawater injection, and finally, subsea compression with a world's first, true multiphase compressor.

A number of case studies where significant increase in production has been seen as a result of implementing subsea boosting at the seabed will be presented. These cases will demonstrate the key production enabling techniques that allow enhanced recovery from deeper waters, as well as production of heavier and more viscous fluids, including high water cut production.
Numerical Simulation of Jet Excavation in Conductor Jetting Operations
Authors: Wang Teng , Li Hao
Published: February 2015

Conductor casing jetting operations have become commonplace in deepwater environments and has become the preferred method of installation in most deepwater environments where seafloor sediments allow the technique to be utilized. Operators have found the technique to be faster than the historical method of drilling a borehole and cementing the casing in place. But very little literature has been published regarding jet excavation mechanism in cohesive soil. In particular, some empirical method ignores the hydrodynamic characteristics of the jet and soil properties.

As the submarine soil is a deformable body whose behavior falls between a linear elastic solid and viscous liquid, its behavior is governed by general theory of rheology. A simple linear model of visco-plasticity, the Bingham rheological model, can describe soil deformation under steady-state stress. The generalized observation was that flow of soil is initiated only when the stress exceeds the yield stress. Beyond this stress, soil flows in a manner similar to viscous fluids at a rate proportional to the stress in excess of the yield stress. On the other hand, the visco-plastic material behaves like solids when the applied shear stress is less than the yield stress.

This article is to clarify the excavation mechanism associated with jet cutting in a cohesive soil, based on computational ?uid dynamics approaches. To investigate the profile of the excavated hole and the ultimate cutting distance of the jet, taking into account both the hydrodynamic characteristics of the jet and the undrained shearing resistance of the cohesive soil. The simulation results using FLUENT reveal that ultimate cutting distance grows with increasing flow intensities and decreasing clay shear strength as well as the distance of jet-soil interface from the nozzle. Based on the research results, propose the expression for jet excavation depth with shear strength and the other factors, which provides an improved prediction tool that can be applied in industry.
Sand Fines Erosion and Asset Integrity Management
Authors: Subramani Hariprasad J. , Rhyne Lee D. , Vedapuri Damodaran
Published: February 2015

Solid particle erosion is an important asset integrity concern that needs to be addressed for existing as well as new oil and gas pipelines. In spite of the sand control/management techniques implemented down-hole, fine sand (< 50–75 microns) often may find its way into the piping components of onshore, offshore, and subsea facilities causing erosion/wear and subsequent pipeline integrity issues. Suitable design of the piping components with capability to monitor wear at hotspots and/or flow manipulations could potentially be made if the erosive impact of this fine sand could be quantified with confidence by predictive methods using Computational Fluid Dynamics (CFD) framework that are validated with lab and field data. Existing erosion models (both CFD-based and correlations) widely used in the industry have been reasonably benchmarked with erosion due to sand particles that are greater than 100–150 microns and the predictions are within ±100% of observations. It is well-known that these existing erosion models predict erosion levels that are in proportion to the particle size (and thereby mass) and so the models will indicate that as particle size decreases, the erosion levels should diminish. Although there is only a limited set of the fines erosion data (both lab and field), the data set indicates that there is substantial erosion unlike what existing models predict. Clearly, the development and validation efforts of the CFD erosion models for fines erosion are still at their infancy. This paper (a) elucidates how predictions from existing CFD-based erosion models fare against limited new lab data and those available in literature, (b) attempts to highlight some of the potential reasons for any glaring discrepancy, and (c) provide some directions for future efforts needed on this topic that are critical to the safe and efficient operation of oil-gas producing/processing facilities.
Miscible Flood Performance of Heterogeneous Layered Reservoirs: Considering Profile Control Through Controlled Fluid Movements
Authors: Ahmed Muzammil , Jaafar M.Z. , Wan Sulaiman W.R. , Hashim Muhamamd
Published: February 2015

Current paper describes the work carried out on a layered reservoir in order to understand the miscible flood efficiency by controlling the velocity field in the individual layers of the heterogeneous reservoir. Heterogeneity in the reservoir can cause the early breakthrough of the solvent, and channelling through least resistance paths. Furthermore, the heterogeneity can be responsible for wider mixing zone between displacing and displaced fluid causing the loss of miscibility in the system, and wider dispersion of the solvent, this reduces the pore scale displacement efficiency of the reservoir.

The major forces involved in the displacement efficiency of the miscible floods such as, viscous, gravity, cross flow and capillary need to be accounted as well to properly model the sweep efficiencies in the system as they are directly responsible for reduced performance caused by viscous fingering, gravity tonguing, and dispersion.

Numerical reservoir simulation is intended to provide the insight into work done on the layered reservoir model where by controlling the injection rates of the solvent into the layers it is deemed to control the velocity fields inside the reservoir since mixing, capillary and gravity forces are all rate dependent, through this, more controlled injected solvent fronts can be produced, which to some extent are capable of increasing the sweep efficiency of the reservoir and prolong the breakthrough time. This is carried out by considering the selective smart injection/production of the solvent in the layers which is more kind of mechanical method of flood profile control although use of smart completions in miscible floods has not been discussed before in the literature. Use of smart completion is thus in current study is applied to the injectors also which is provided to give analysis on reservoir sweep efficiencies under the different microscopic and macroscopic driving forces. This can be significant in existing or potential EOR fields where smart completions already exist and can be utilized much effectively for the purposes of EOR operations.
Non-Metallic Materials in Supercritical CO2 Systems
Authors: Abas Ahmad Zaki , Mohammed Nor Azmi , Suhor Muhammad Firdaus , Mat Sa'adan
Published: February 2015

Non-metallic materials are widely used in many sectors within a Carbon (dioxide) Capture and Storage (CCS) programs. They include such as nitrile butadiene rubber (NBR), polytetrafluoroethylene (PTFE), and Viton. They are used as seals in corrosion monitoring and in-line inspection tools. These non-metallic materials can suffer from decompression damage (e.g., rupture, explosion, blistering, and swelling), to some extent, when the contained gas is subjected to either scheduled or accidental decompression process. The damage will undermine the operational integrity of the tools. This paper presents the findings of the various types of non-metallic materials (polytetrafluoroethylene [PTFE], polyetheretherketone [PEEK], fluoroelastomer [FKM] and perfluoroelastomers [FFKM]), tested at 150 bars and 80°C in supercritical CO2 fluid containing 5,000 ppmv water. The materials were exposed for two weeks under conditions of slow (0.3 bar/min) and rapid (5 bar/min) decompression cycles. The samples were measured for changes in weight, dimensions, and hardness, and they were also examined photographically before and after the exposure. The results showed that PTFE and PEEK were not affected under both decompression rates, whereas small changes were observed for FKM and FFKM. The findings thus indicate the suitability of these non-metallic materials for use as seals in corrosion monitoring and inspection tools provided they are produced from high grade materials
An Effective Constitutive Model for Unbonded Flexible Risers
Authors: Pham D.C. , Guo T.F. , Zhang Z. , Narayanaswamy S. , Edmans B.
Published: February 2015

Recent developments in the offshore and deepwater industry have increased interest in the use of unbonded flexible risers for deep water applications, and in the development of improved large-scale models for global dynamic analysis. Flexible risers are slender composite structures consisting of multiple polymer layers and spiral wound steel layers with complex geometries. To better understand and capture the complex behavior of actual unbonded flexible risers, in which global response is influenced by the ability of layers to slide over each other, incorporating nonlinearity in global dynamic analysis of risers and employing a suitable and reliable constitutive model increase the accuracy of the riser motion and stresses predictions. In this work, a novel elasto-plastic constitutive model is developed to account for the macroscopic response of unbonded riser structures. Determination of the parameters of the constitutive model is achieved through calibration of riser's response plots obtained by numerical simulations of detailed Representative Volume Element model of the riser. Co-rotational hybrid beam elements are used to implement the developed constitutive law, created using a user-defined element subroutine in Abaqus. It is shown that the integration of hybrid beam elements and the proposed constitutive model effectively simulate the nonlinear response of unbonded flexible risers under various working conditions by accounting for effects of internal and external pressures, coupling of axial and twist deformations and slip between the different layers of the riser.
An Integrated Approach to Understand the Remaining Potential and Ultimate Hydrocarbon Recovery of a Giant Carbonate Gas Field, Offshore Sarawak, Malaysia
Authors: Rabani Mas Nur Afiqah , Adams Erwin , Ryba Artur , Harwijanto Josef , Warrlich Georg , Fui Lee Hon , Shields Daren , Tan Abel , Mukhopadhyay Arunesh , Chai Xintee , Amir Amie , Palm Danielle , Seng Lee Bor , Balakrishnan Gopi , Hong Lay , Van Zandvoord Walrick
Published: February 2015

A large carbonate gas field in the Central Luconia geological province, offshore Sarawak, Malaysia, is being operated by Sarawak Shell Berhad (SSB) and partners Petronas Carigali and Nippon Oil.

After more than 8 years of production, a full understanding of the field is required to assess near-term WRFM opportunities and to evaluate the remaining future development potential. The aims are to ensure the delivery of gas at a sustained level of gas volumes and with a manageable water level and at the same time improving the ultimate hydrocarbon gas recovery.

Predicting and preventing water breakthrough at the existing producers currently forms the challenge for the WRFM.

To deal with the above challenges and opportunities, the integrated methodologies employed include:Reservoir surveillance through timely data acquisition of fluid movement measurement in the observation well and time-lapse (4D) seismic, i.e. monitoring contact movementTogether with the historical well performance, a continuous integrated subsurface-surface study is performed with the aims to improve the field hydrocarbon gas recovery through optimization of WRFM, reservoir models, in-fill identification and near future field developmentContinued optimization between subsurface and surface facilities

A reservoir surveillance program has been in place since first gas with one of the deviated wells being dedicated to monitor the fluid contacts on a yearly basis. To complement this, two time-lapse (4D) seismic surveys have been successfully acquired in 2008 and 2012 to provide a field wide image of fluid movements and contacts. In spite of only two narrow swaths acquired around the platform area, the 2008 4D seismic has assisted in drilling two in-fill producers granting production to maintain a constant level. In 2012, a much larger 4D swaths were acquired covering the majority of the field. The high quality 4D data provides more crucial information, including indication that gas has likely been produced from a much wider area including the southern area.

The two 4D time lapse data enable to constrain the dynamic (and also static) modeling significantly and monitoring the dynamic behavior of different reservoir geobodies (reef margins, karst, faults) through production lifetime of the reservoir units.
Riser Gas Risk Mitigation with Advanced Flow Detection and Managed Pressure Drilling Technologies in Deepwater Operations
Authors: Toralde Julmar Shaun S. , Wuest Chad H.
Published: February 2015

Studies have revealed that gas kicks unintentionally entrained in oil or synthetic based mud in deepwater drilling operations at water depths greater than 3000 ft are unlikely to break out of solution until they are above the subsea BOPs. The rig diverter is conventionally used to vent riser gas with minimal control and with considerable risk and environmental impact through the uncontrolled discharge of drilling fluids.

Riser gas handling (RGH) systems currently being offered provide a reactive solution to the problem by supplying a riser joint equipped with additional components for this specific purpose. This joint is normally composed of a retrofitted annular BOP and a flow spool with hoses that is installed on top of the rig marine riser. An alternative and proactive approach to riser gas handling, which we prefer to call riser gas risk mitigation, is proposed by utilizing managed pressure drilling (MPD) equipment. MPD involves the use of a rotating control device (RCD) to create a closed and pressurizable drilling system where flow out of the well is diverted to an automated MPD choke manifold with a high-resolution mass flow meter that increases the sensitivity and reaction time of the system to kicks, losses and other unwanted drilling events.

Experiments and field deployments have shown that the deepwater MPD system can detect a gas influx before it dissolves in oil-based mud, allowing for management of the same using conventional well control methods. Since the MPD system has already closed the well in, automatic diversion and control of gas in the riser is also possible, if required, thereby further minimizing the likelihood of an environmental discharge should a riser gas event occur. Experience gained from deepwater MPD operations in Asia Pacific will be presented to illustrate this.
Minimising Uncertainty for Marginal Field Development by Maximising the Value of Appraisal Wells: Measuring Stress and 3D Anisotropic Rock Properties in the Malay Basin
Authors: Jones M. , Reilly M. , Donald A. , Heidari B. , Oo A.
Published: February 2015

Description

Appraisal wells prior to field development provide the only opportunity to gather data required to maximize production through completions and reduce costs through optimized operations. Full understanding of the stress state in the earth, anisotropic rock mechanics and pore pressure is essential for safe, efficient drilling of the deviated development wells and production to their full potential. Understanding uncertainties in these parameters affects the economic production of these assets.

A recent appraisal well in Hess's Bergading Field, drilled for a shallow sand, provided the opportunity to use it as a laboratory for future development. Full waveform sonic data, wellbore images, stress testing and full cores were gathered.

Continuous estimates of anisotropic rock mechanical properties were compared and calibrated with core The 3 dimensional shear moduli were measured and continuous magnitudes of reservoir horizontal stress were obtained. Although the borehole itself was close to circular showing no break-out, larger than expected horizontal stresses were observed and the mini-frac failed to achieve breakdown at a pressure of 4500psi at 4000ft.

State of the art sonic measurements providing shear radial-profiling from the sand-face into the far-field allowed direct derivation of horizontal stress magnitudes in the sand. These measurements also predicted a higher formation breakdown pressure than was applied in the mini-frac test.

Application

Well-bore stability, sanding and perforating all depend for their effective utilization on an understanding of the rock mechanics and state of stress of the material around the borehole. The horizontal stress field and the rock strength define the failure modes and predict stability and sanding behaviour in deviated wells planned for field development.

Results

The horizontal stresses from the sonic measurements were used to generate a revised safe drilling window for mud-weight. Subsequent core test results were able to describe plastic vs. elastic behaviour in the near-wellbore region to predict failure modes. Perforation recommendations and sanding predictions were also produced

Significance

Results are significant because they speak to the underlying geology of the basin, the behaviour of individual boreholes within that setting and the optimization of strategies in well, perforation and completion design, thus reducing cost and maximizing production
Unconventional Shale Gas Drilling Comparison in Sichuan Basin, China Different Approaches Aim for Same Target
Authors: Sun Haifang , Bai Jing , Huang Bing , Chen Weiqing , Hong Yuandong , Moh Thomas , Zhou Feng
Published: February 2015

Low cost, high technology and fast ROP are three main factors which related to successful development of unconventional shale gas all over the world. Local operator and international operator are using different approaches to develop shale gas in Sichuan basin, where is a hot place for shale gas chasers in China. Both operators have some filed application lesson learnt to improve drilling efficiency and save cost during past 3 years:Flexible local well structure optimization design reduces loss risk.Local factory drill is proven to improve working efficiency and reduce cost per well.Local service providers help to reduce cost, especially, local DD/MWD/LWD service.Local Well placement concept reduces downhole collapse issue through filed application lesson learnt.New push to bit and point to bit combination tool has high efficiency to improve ROP, especially, in curve section.Near bit gamma ray/Gamma ray image is a useful tool for high dip angle / multi-faults formation horizontal section well placement, to avoid geological sidetrack.Bit optimization helps to improve ROP and extend downhole working life.

Through above filed applications, average cost of international operator is 1.7 times of local operator, but on bottom ROP is 1.5 times faster than local operator. Both operators' drilling efficiency has average 70% improve which based on previous 3 years learning curves.

Local operator tries to factory drill 6 wells per pad with 300m well spacing and 8 wells per pad with 400/500m well spacing separately next step and find the best well placement to improve production in Sichuan basin. The production target of unconventional shale gas will be attempted to 600-1000 X 108 m3 per year until 2020.