bluuebunny/crossref_metadata_2025 huggingface dataset:
Marginal Field Development: Innovative Rig-Installed Light Weight Structure Platform Using Drilling Jack-Up Rig
Authors: Lai W. Y. , Jabil J. , Razak Z. A.
Published: October 2013

This paper presents an innovative approach undertaken by a joint venture company of three ASEAN national oil companies in developing a marginal field, offshore Malaysia. This paper focuses on the development strategy, execution and challenges of the project in utilizing a jack up drilling rig to install a Light Weight Structure (LWS) platform.

The LWS platform is part of a Cluster Development Project, which is the second marginal field to be developed by the tripartite alliance in Malaysian waters. In view of the small reserves and sub-surface uncertainties, as well as many other prospective small fields in the block, light weight and relocatable facilities proved to be an attractive solution for early reserves monetization.

Through the development project, the company aims to pioneer marginal field projects in Malaysia by utilising ‘fit-for- purpose’ design facilities supported on the LWS platform that was installed by a jack up drilling rig and connected to a Mobile Offshore Production Unit (MOPU). Additionally, the project was executed as a fast-track project with First Oil achieved ahead of schedule. The offshore installation was completed within three (3) months upon award of the Offshore Installation Contract. This has proved to be an effective execution by a small integrated project management team set-up by the unique tripartite alliance.
A Cost-Effective Method to Enhance Oil Recovery of Water-Flooded Reservoirs: Air-Foam Flooding
Authors: Jiang Youwei , Wang Bojun
Published: October 2013

Water-flooding is a widely used recovery method of mature oilfields. In recent years, most of the mature oilfields are already at the medium-high even ultra-high water cut period due to water breakthrough and invalid water circulation. Air foam injection has been optioned as an EOR technique to block high permeability water zones and/or increase sweeping and displacement efficiency. There are medium-high average permeability (1016×10-3μm2) oil bearing formations and ultra high permeability layers or channels after water flooding in Dagang oilfield, Petrochina. After 42 years of water injection, the recovery efficiency achieved was only 37.6%, but average water cut has reached to over 97%. In this study, Laboratory experiments were focused on low-temperature-oxidation (LTO) characteristics of oil samples, selection and evaluation of the foam agent and core foam-flooding. Through isothermal oxidation experiments, the influence of formation sand, formation water, foams, clay mineral, temperature and pressure on LTO reactions is investigated qualitatively. It is also analyzed that the changes of component and properties of crude oil before and after the LTO reaction. Selection and evaluation of basic property of the foam agent on formation condition has been done through the device of high temperature and high pressure foam agent evaluation. After that, some dynamic foam displacement experiments are also performed, including single-tube and parallel tubes displacement experiments of air foam at different water saturations. Experiments prove that during the air foam flooding process, oxygen can be effectively consumed in the formation, and the foam can effectively plug high permeability layers to expand swept volume. A pilot project has been designed according to the study in Dagang oilfield. The issues related to safety and corrosion control during air injection and the project economic assessment were also addressed in this paper.
Reservoir Connectivity Analysis and Its Application in Development of a Highly Compartmentalised and Stacked Reservoir in Malaysia
Authors: Musani N. T. , Anggono H. , Ataei A.
Published: October 2013

Reservoir connectivity analysis plays an important role in understanding and successful development of compartmentalized and stacked reservoirs. The field compartments are initially defined based on the geological boundaries such as faults, shale layers, and other geological barriers. Well penetrations, fluid contact measurements, and initial pressure distribution surveys will complete the static connectivity of the compartments prior to production data. Reservoir behavior in the production time scale may change the initial understanding of the compartments system. Dynamic connectivity can bring surprises which affect the development plan and may require more investment to manage them. For a brown field development with such a complex structure, it is vital to have a systematic analytical approach in place to integrate the available data which had highlighted the missing gaps for the future development plan and helped to locate the remaining oil in place.

This paper demonstrates the above concept in Baram field; a highly compartmentalized and stacked reservoir located offshore Miri in Sarawak, Malaysia. Based on the available production data and by using reservoir engineering techniques like material balance, reservoir uncertainty analysis and history matching; dynamic reservoir connectivity was defined. Fault seal analysis was evaluated to understand the behavior of the faults during the depletion phase of the field. The estimation of fault’s transmissibility compliments the material balance outcome and was refined in dynamic modeling/ history matching. Geomechanics study of the field proved useful to evaluate the impact of stress change during the future pressure maintenance study as a part of the brown field development plan.
"Evaluating Fractured Carbonate Reservoirs: Sarawak Basin Case Study, East Asia"
Authors: Bt Zulkipli Siti Najmi , Kyi Ko Ko , Haddad Sammy , Johan Zailily , Wa Wee Wei
Published: October 2013

In the search for hydrocarbons, fractured carbonate formation drilling presents significant challenges associated with fluid losses and well control. These challenges also include open-hole formation evaluation. As a result, cased-hole analyses including production logging presented an opportunity to achieve complete formation, pressure and fluid evaluations in these fractured carbonate reservoirs.

In this appraisal case study, it was crucial for the G&G team to evaluate zonal productivity, fluid type, and formation pressure to further manage uncertainties in reserves booking. The target reservoir, which consists of cycle IV and cycle II carbonates, is naturally fractured with significant predicted gas reserves and unknown water contact. The 2nd well in the field has been recently successfully drilled to TD with a combination of conventional drilling with LCM to treat partial losses, and unconventional drilling with Light Annular Material (LAM) and pumping seawater through the annulus when total losses were encountered.

Though drilling was successful in this hostile carbonate environment, the main objective to obtain pressure measurements suitable for gradient analysis in open-hole environment at balance condition has raised uncertainties in their technical validity. Nonetheless, due to high risk of gas migration from fractures, the well needed to be secured immediately right after successful drilling. It was cased with 7" liner and cemented. This left the operator staging for cased-hole wireline production logging to close the evaluation gaps.

Cased-hole wireline production logging program was designed to help in providing a better understanding on the fluid type, density and zonal contribution. When production log results were combined with cement log evaluations, they revealed important information that helped with better understanding the source of produced fluids beyond the standard production log interpretation. Results also presented lessons learned for future wells to be drilled in similar environment. Field results, challenges and lessons learned will be presented in this work.
A Novel Nano-Composite Fiber Laden Viscoelastic Fracturing Fluid for Coal-Bed Methane (CBM) Reservoir Stimulation: Laboratory Study and Test
Authors: Xiao Bo , Zhang ShiCheng , Zhang Jin
Published: October 2013

Due to strong adsorption characteristic and extremely developed natural fracture system in coal, improper choice of fracturing fluid will result in two major problems: one is damage to the coal formation and hydraulic fracture; another is the ineffectiveness in hydraulic fracture creation and propagation. With the merits of small damage and easy flowing back, viscoelastic surfactant(VES) fracturing fluid is becoming a preferred option. A high surfactant concentration may be necessary to enhance the proppant-carrying capacity, but as a tradeoff, it has a bigger potential to increase the absorption loss in the seam and create barriers to rod micelle breaking in low temperature condition.

By introducing nanoparticles in the conventional polyester fiber, a new kind of nano-composite fiber which has obtained major improvements in functional and structural properties was synthetized. A novel Nano-composite Fiber Laden VES(NFVES) fracturing fluid was developed. A series of evaluation tests were performed in laboratory. The results shown this fiber can disperse easily in the fluid and an addition of small amount(0.5%) can enhance the proppant-carrying capacity drastically. To achieve the equal proppant-carrying capacity, the surfactant concentration can be decreased from 2.5% to 1%, which not only reduces costs but also lowers the adsorption of the surfactant in the seam and rock surfaces greatly. The rod micelles can be broken easier at the same time. Friction can be cut by 20% via adding 0.7% nano-composite fiber under the shear rate of 5000s-1. Meanwhile, nano-composite fiber can prevent backflow of proppant effectively. Leak-off of fluid and aggregation of coal scraps can also be mitigated significantly. Continuous degradation of the fiber takes place with the passage of time under the formation temperature, thus reducing the potential damage to the coal seam.

The excellent performance of the NFVES fracturing fluid in the laboratory evaluation enjoys great potential and vast development prospects in CBM stimulation.
Technique of Water Control and Oil Recovery Based on Water Plugging Combined with Fracturing in Low Permeability and High Water Cut Oilfield
Authors: Yang Gao , Honglan Zou , He Liu , Jianwen Yan , Qinghai Yang , Fuchao Sun
Published: October 2013

In low permeability oilfield, normally fracturing is applied for production and the water injecting pressure is quite high. As most of the major oil reservoirs are flooded by water after fractured, the production rate is very low. With the oilfields further developed, the number of high water cut wells increased. How to further tap the remaining oil and enhance the oil recovery is becoming a big challenge to us currently. In Daqing low permeability oilfield, a pilot test of pressure plugging, water control and oil recovery of high water cut wells was conducted and achieved a good result. The test was including: 1) Further verified the understanding of well and reservoir selection and established the selection standard of the pressure block, water control and oil recovery technique for fractured reservoirs in low permeability oilfield. 2) Optimized field operation process of pressure block, water control and oil recovery. Compensator + K341-114 packer + fixed pressure valve + K341-114packer + ball seat was designed as the plugging string. Small diameter string was studied to repair casing damaged wells. 3) Optimized the chemical plugging agent and developed the fracturing technique of plugging the water cracks through compound water plugging. Production enhancement and water drop were observed through large scale field application.
First Broadband, Full Azimuth Marine Seismic Survey in Malaysia: Deployment of Two Cutting Edge Acquisition Techniques
Authors: Chandola Sandeep K , Tham Michelle , Ho Koon Hong , Foo Low Cheng , Velayatham Tayallen , Mahmud Nurhakimah , Muhamad Abdul Aziz , Sazykin Artem
Published: October 2013

PETRONAS recently conducted the world’s first 3D broadband full azimuth marine seismic survey by an operator in East Malaysia. The survey seamlessly deployed two of the most cutting edge acquisition technologies concurrently i.e. the circular shooting technique for extending the azimuth sampling and the constant gradient slant cable towing technique to extend the bandwidth sampling.

The legacy narrow azimuth 3D streamer data, acquired in the year 2001, suffers from poor imaging in the zone of interest. Though there were two successful wells with hydrocarbon discovery in the areas which have good seismic data quality, the area in between these wells is characterized by poor quality seismic data not amenable for interpretation and delineation of the reservoir. This poor data zone is understood to be caused by the inadequate illumination of the target horizon and low energy penetration through the monotonous shale in the overburden.

Prior to the data acquisition, a survey design and modeling study was performed to select the optimum acquisition technique. A 3D earth model was created using the surface seismic and borehole data. 3D illumination ray tracing was performed at the target horizon using different acquisition geometries such as conventional narrow azimuth, multi azimuth and full azimuth circular shooting.

A pilot broadband circular shooting survey was conducted over a subset of the study area based on the parameters derived from the survey design and modeling study. The time imaging processing result shows significant improvement in the seismic image at the target interval as well as the shallow level as compared to the legacy data. The extension of azimuth sampling and broader bandwidth enabled by the slant streamer circular shooting acquisition technique provides a superior image compared to the conventional narrow azimuth, flat streamer legacy data. These advanced acquisition techniques have the potential to offer solutions for other areas with similar imaging challenges in South-East Asia.
The Next Wave of LNG, An Economist's View
Authors: Gurney David S
Published: October 2013

Fiscal regimes were initially designed for oil production. These projects have materially different investment, payback and risk profiles to large gas/conventional LNG projects and differ again to the new unconventional and giant multi-phase LNG projects undertaken in the current high price, high cost environment. Although some Governments have slightly modified their regimes to incentivise gas production, there have been no major redesigns to reflect the differing nature of modern LNG and unconventional gas developments and the expected investment environment.

This paper examines a range of generic conventional and unconventional LNG projects under various typical PSC and concession regimes and calibrates this analysis against a typical material oil development. It presents the project from the perspective of both the investor and host Government.

When planning a major investment, even at the early licence entry stages, the investor should undertake significant and detailed analysis of the precise nature and timing of the cash flows to the various stakeholders. Investor intuition, built up over a period of oil and ‘classic’ style gas projects may not hold true for the new wave of LNG investments. In addition, the scale of the new phase of projects may create significant sovereign risk as the long duration of investment post project-start-up defers the time until the state sees the income that it sees as its fair share of the resource bounty.

From the governmental side, careful consideration must be given as to whether the existing hydrocarbon fiscal terms that may have been appropriate for the previous generation of projects will still prove to be correct for the new generation of investment, the competitive global market for LNG and will correctly align the various parties’ interest and still incentivise investment.
Optimisation of Surfactant Concentration to the Foam Generation and Swelling Ratio of CO2 Foam Flooding in Light Oil Reservoir
Authors: Saputra D. D. , Bae W. , Permadi A. K , Muslim M. , Pham T. H. , Efriza I. , Gunadi T. A.
Published: October 2013

The implementation of CO2 flooding is steadily increased in the world since 1980s and is used in mature fields after water flooding. The main reason of using CO2 gas for tertiary recovery is because of its capability to reduce oil viscosity and to make crude oil swell, hence improve oil mobility. However, there are some challenges such as poor sweep efficiency, low oil recovery due to viscous fingering and gravity segregation, and inefficient gas utilization in the field. CO2 slug combined with surfactant slug will produce foam that will reduce gas mobility and block the high permeability zones in the reservoir. Therefore, it is necessary to have a comprehensive study about surfactant concentration effect and swelling ratio of CO2 foam flooding to further improve oil recovery.

The objectives of this paper is to know the optimal surfactant concentration in the injection slug and to analyze the swelling effect during CO2 injection. Several parameters that was analyzed were volume changes after swelling, surfactant concentration, foam stability and pressure and temperature changes. The study started with conducting several experiments. First, the optimal surfactant concentration is evaluated by using spinning drop interfacial tension apparatus for knowing the interfacial tension of oil/surfactant. The foam stability experiment was conducted by using foam generation and foam stability apparatus. Then, the swelling factor was obtained by doing CO2 swelling test simulation.

The result of this study was optimization of the foam flooding design in light oil reservoirs with considering surfactant concentration and swelling ratio effect. Using optimal surfactant concentration for foam generation and CO2 concentration from swelling ratio measurement, it will improve sweep efficiency of the injected fluids and decrease the interfacial tension of oil.

The study presented in this paper can be used to design the optimal CO2 foam flooding parameter for light oil reservoirs.
Multilateral Well Completion Design Using a 3D Reservoir Simulator: Real Application in Offshore Western Australia
Authors: Jackson Elliott , Di Martino Gianluca , Marshall Craig
Published: October 2013

The need to develop thin oil reservoirs and heavy oil plays is fast becoming common place in the North Western Shelf (NWS) of Australia. Drilling horizontal multilateral wells is often a requirement to maximise the recovery from a thin oil column and to ensure a field remains economic. Early water coning and heterogeneity uncertainty are problems associated to these reservoir types and it is with the help of Inflow Control Device (ICD) completions that we can combat these issues.

This paper focuses on investigating the technical aspects of multilateral completion design; including packer spacing, ICD calibration, modelling, and upscaling. Of the numerous ICD types that exist, two ICDs (nozzle and spiral) are considered. Using 3D reservoir simulation software, we investigate the effects of calibrating the ICD’s parameters in order to refine a simulation model with historical production data. Methods of upscaling the ICDs to reduce model complexity, computation time and the ability to tune parameters are covered in an attempt to understand the differences and benefits of each ICD type.

Although preset ICD models with default parameters are provided in most simulation packages, ICD calibration using historical data is required in order to achieve a model that can accurately portray the production of a reservoir. It is important that the Reservoir Engineer informs the completions manufacturer about unknown ICD model parameters during the development phase of a field so that an accurate production profile can be created thus avoiding any disappointing outcomes in the future.
Sand Management in Tangguh Big Gas Wells
Authors: Warnken Dean , Asri Fitria Nila , Anantokusumo Ferry , Samusamu Randy Lester , Ichwan Ichsan Obigesto
Published: October 2013

Tangguh is a Liquefied Natural Gas (LNG) greenfield development located in Bintuni Bay, Papua Barat, Indonesia. There are fourteen wells that are designed to produce up to 240 MMcf/D per well. Sand and other solids from the reservoir are managed with a comprehensive, holistic strategy to provide operational assurance from the sandface to the processing facility.

The Tangguh gas wells are identically completed in the Roabiba formation with seven inch monobore cased-hole perforated completions. Each well flowline is equipped with a dedicated non-intrusive acoustic sand detector and wet gas flowmeter. Well bottomhole pressures are monitored continuously with permanent downhole pressure sensors.

Extensive log and core analyses suggested that Roabiba formation competency was sufficient to not require downhole sand control. Similarly, surface processing facilities and flowlines were constructed with a design basis of very low levels of sand and other solids production. Produced liquid yields are low and formation water is not expected until the latter years of field depletion.

An integrated sand management strategy has been implemented since pre-startup with an underlying theme of formation sand prevention. Following completion, all wells were methodically cleaned up to remove potential formation drilling damage and other completion related debris. Wells were initially cleaned up to 100 MMcf/D with rig testing equipment and later ramped up to their maximum allowable rate to the permanent production facility.

Measured formation sand production is negligible to date. Real-time well performance is monitored continuously and managed with rigorous constraints to minimize potential sand and other solids production. Detection of acoustic signals over a pre-determined limit are investigated and followed up with further action as necessary.
Integrated Reservoir Management Helps to Arrest Decline and Increase Production Significantly – A Case Study of Angsi
Authors: Mandal Dipak , Mansur Roslan , Matali A. A.
Published: October 2013

With lesser new discoveries, integrated reservoir management has become the key tool to assure committed production. In Angsi B reservoir, injection for pressure maintenance was initiated with start of production. Simultaneous water injection at the southern flank and also at GOC to the south was initiated with the plan to arrest gas cap expansion and sandwich oil for better recovery. Injectivity issues, unavailability of required injection volume, increasing offtake led to variable pressure decline in the reservoir. Decline in production more than predicted was thus observed due to resultant uneven sweep. Preferential expansion of the gas cap to the north led to wells getting high GOR resulting in further decline. Well integrity issues surfaced which led to certain wells to be closed prematurely adding to reservoir management problems. This led to critical well and sector performance analysis to understand the reservoir dynamics. Study indicated resaturation loss of reserves at the prevalent pressure maintenance strategy. Various alternative pressure-production plans were evaluated to prevent reserve loss and decline in production. The best plan included a change of injection strategy, temporary closure of HGOR wells, profile modification in injectors and producers, a structured reservoir surveillance programme and integrated discipline weekly meeting to monitor and guide this change of reservoir management. The results were very rewarding as it not only helped in arresting pressure andpreferential gas cap expansion, but also arrested and reversed production decline.

This paper details how the alternative reservoir management approaches were evaluated within current constraints to agree on the current reservoir management plan, what were the different strategic actions taken, monitored, evaluated and revised to effect the change. Convinced of its effectiveness, similar integrated reservoir management approach has been initiated in another reservoir of Angsi which already shows indication of decline getting arrested.
Water Injector Perforation – A Challenge and an Art
Authors: Kumar Prakash , Singh Alok Kumar , Parasher Arunabh
Published: October 2013

Field X in India has been developed with Injectors wells & Producers wells in an inverted 9 spot pattern. Some of the producers are Cased & perforated using TCP (shoot & auto release drop system) whereas most of the remaining producers are completed with standalone screens of different types like conventional, ICD’s and SSD types. Guns were deployed with rig (using E-line or drill pipe) and anchored on casing. The wells were further displaced with diesel to achieve desired underbalance.

The injector wells are 4-1/2" mono-bore. In some of the Injectors, TCP gun was lowered on E-line/drill pipe and installed on bottom anchor. In a few cases, the TCP gun assembly failed to release & gun didn’t drop (probably due to sanding issue or high deviation). Coiled Tubing conveyed hydraulic release pulling tool was used to latch and drop the TCP gun into the sump. Advanced fishing tools like hydraulically activated elbow, indexing tool, etc. were used. In some other wells stackable gun system were used as the perforation technique. Squeezing and bleeding of nitrogen was done to provide underbalance in some cases. For wells with smaller perforation intervals, E-line conveyed guns and sand jet perforation was also used successfully.

As an alternate to anchor based system flagged CT was used to deploy the guns using a hydraulic release tool. Post- perforation, the gun was run to the sump & released by activating the release tool by pumping water. For wells where depth correlation was important, telemetry enabled coil was used for perforation. As a further improvement to the technique, hydraulic flow release system was successfully replaced with an automatic gun release system for releasing and dropping TCP gun conveyed on CT.

This paper presents the results, analysis and case history of different gun system used for water injector perforation.
Tubular Bells: A Case Study of Large-Scale Batch Sets
Authors: Vizinat Jacob , Sallee Adam , Metz Steve , Parlipiano Alan
Published: October 2013

The field development of Tubular Bells, in the Mississippi Canyon (MC) area of the Gulf of Mexico, began with a nine-well batch set drilled riserless in water depths of approximately 4,500 ft. The batch drilling concept was implemented to mitigate the risk of various shallow hazards and to maximize performance through repetition of operations (Valdez and Fleece 2005; Eaton et al. 2005; Flannery and Choo 2008). Each well in the batch set consists of a 36-in. conductor, a 32.5-in. drill-ahead section to set 28-in. casing, and a 26-in. section to set 22-in. casing approximately 3,400 ft below mudline (BML). A low- inclination, low-dogleg batch set was critical for the development plan because the target reservoirs are at 25,000 ft true vertical depth (TVD) and up to 10,000 ft of step-out from the surface location. Rapid evolution of the drilling learning curve enabled reduction of jet-in times by 75% and an increase in rate of penetration (ROP) by 30%. The batch set was delivered in 86 days of continuous operations, was completed 31 days ahead of schedule, and underspent the authorization for expenditure (AFE) by 13%. Considering total days, the average time per well was 9.5 days, or 7.5 days per well when considering operating time alone. The well with the shortest duration took 5.8 days to complete compared to the longest well of 12 days.
Optimisation of Compressed Natural Gas Marine Transportation with Composite-Material Containers
Authors: Nikolaou Michael , Wang Xiuli , Economides Michael J.
Published: October 2013

Marine transportation of natural gas is critical for its monetization. Pipelines and liquefied natural gas (LNG) are the established technologies for offshore natural gas transportation, with compressed natural gas (CNG) recently proposed as an economically preferable alternative under certain conditions.

In previous work, we have delineated areas in a transportation-distance/gas-volume diagram, where each of the three transportation means mentioned above is economically most attractive. In general, once offshore pipelines are excluded because of water depth and sea-floor terrain limitations, CNG transportation is considered attractive compared to LNG for relatively small volumes and short distances. Until recently, the preferred material for proposed CNG containers has been metal, for reasons of simplicity, robustness, and development cost. However, metal CNG containers have a number of disadvantages, the most obvious of which is that the container itself may be several times heavier than the contained gas, and, consequently, such gas may be only a small fraction of the cargo carried by a loaded CNG ship.

Composite containers are an alternative to metal, with a number of advantages. First, composites are significantly lighter than metal. Second, composite containers can reach considerably higher containment pressures (hence capacity), while still maintaining lower weight compared to metal. Finally, composite containers are much less prone to corrosion, and as a result can contain gas that has not been fully treated. These facts make composite containers an attractive proposition and greatly increase the overall attractiveness of using CNG to monetize stranded gas.

We present here a thorough study using both metal and composite containers and optimized operating conditions, such as pressure and temperature, to explore the applicability of CNG for marine stranded gas transportation. A new map of the economic attractiveness of LNG and CNG as a function of transportation distance and gas volume is presented, showing a considerably expanded area of CNG preference over LNG.
Sand Control and Gas Well Production Optimisation in a Multilayer Reservoir Gas Field
Authors: Sukotrihadiyono Tejo , Malau Aldani , Ganes Sugi P , Aliefiyan Nursanda M
Published: October 2013

Lagan field was discovered in 1988 and is located in South Sumatra, Indonesia. Lagan is a gas field that consists of 30 wells and produces from 7 different sand layers with three faults. Along with reservoir pressure depletion, the pressure system was reduced as a strategy to maintain the gas production. In 2009, it was discovered that sand was being produced and was eroding surface control equipment during system conversion from medium pressure to low pressure.

Due to limited core data, the initial challenge for conducting a sand control study was to identify which wells and which layers were producing the sand. To resolve this problem, four wellhead de-sanders were installed at four different wells, all of which produced from different sand layers. The next challenge was to find and apply a suitable sand control method by considering the urgent need to accelerate the application of sand control, limited well accessibility and rig mobility due to field location and road conditions, cost and application effectiveness. Wellhead de-sander was eventually selected as the most suitable sand control method for this field. The design and fabrication of the wellhead de-sander were completely in-house and were continuously improved to enhance the quality and quantity of sand trapping.

After one year’s application, the wellhead de-sander has proven its effectiveness by reducing the amount of sand carried out to the station, decreasing production separator downtime, and eliminating surface control equipment failure cases. Until now twelve wellhead de-sanders have been installed in Lagan field to increase gas production reliability, with a total cost saving of up to USD 648.000. This paper elaborates on the road map for the sand control study and its application in a multi- layered reservoir gas field with limited subsurface data, explains how well-modeling was used to estimate the strength of sand consolidation, and describes the step by step process for optimising wellhead de-sander design.
Drill-Cuttings Analysis for Real-Time Problem Diagnosis and Drilling Performance Optimization
Authors: Karimi Moji
Published: October 2013

Drill cuttings have always been used to gather data from subsurface formations. Since the onset of the drilling industry, mud loggers have used cuttings to plot the lithology column. Reservoir drill cuttings have also been used to further understand formation properties, such as porosity and permeability. In addition, cuttings have been the subject of waste management research for years. Cuttings analysis is an important aspect of real-time drilling operations and the correct sampling, measurement, and interpretation of cuttings help prevent problems and improve drilling performance. The first part of this study describes the sampling and measurement of drill cuttings, while the second examines data interpretation.

Historically, cuttings analysis has been done by the solid control crew to enhance solids-removal efficiency and by mud loggers to obtain subsurface data. Although these two groups communicate their analyses with the drilling engineer, current visual inspection and sampling procedures provide information that is potentially unreliable for real-time drilling decisions. Cuttings affect drilling fluid properties, annular-pressure losses, hole cleaning, wellbore stability/integrity, penetration rate and many other drilling considerations. Cuttings properties such as particle-size distribution, volume, shape, etc., can reveal the start of a drilling problem or offer justifications for decisions to improve performance. Reliable measures must be in place for taking accurate samples and reporting related properties to enable the drilling engineer to make meaningful correlations. This study intends to provide guidelines on sampling and measurement methodology for the benefit of drilling engineers.

With recent advancements and the introduction of real-time particle-size distribution and Coriolis in-line flowmeters, new data sources are available. These tools provide plenty of valuable information, but decisions need to be made about where, when, and how to take samples for reliable output data. Particles mixed with cuttings that are not generated by bit action, e.g., cavings and mud additives, also need to be accounted for and differentiated while sampling and measuring cuttings. There are correlations between drilling problems and cuttings properties; however, if detected early, these problems can be prevented to enhance drilling performance. Early detection is contingent upon a reliable sampling method, which represents the annular cuttings, interacting with the formation. Thus, a procedure is proposed for proper sampling and measurement of cuttings.
Coalbed Methane Productivity Measurement with a Wireline Formation Tester Dual Packer
Authors: Cholid Mas , Paolo Mengoni , Suriyanto Olivia , Weatherall Glyn
Published: October 2013

Coalbed methane (CBM) plays usually consist of multiple zones with geologic variability within the areal extent of the play. One of the key indicators of well productivity potential is permeability, which is highly variable zone by zone and area by area. Permeability is also important for understanding gas in place (GIP) and production variability, designing the completion, optimizing well spacing, and diagnosing production problems. Numerous tests may be required to develop a statistically valid permeability data set. The longer rig time and lower-than-expected success ratio of conventional tests are considered the main obstacles in obtaining such a data set.

The wireline-conveyed formation tester (WFT) used with a dual packer provides measurements of the permeability, skin, pressure, fracture flow regime, reservoir heterogeneity, and state of saturation of the coal seam through drawdown and buildup. Compared with conventional testing, improved operational efficiency is achieved through more efficient wireline conveyance, improved packer isolation, reduced wellbore storage, ability to conduct downhole fluid analysis, precise downhole rate control, and surface readout and real-time data monitoring and interpretation for informed decisions.

Measurement in the openhole conditions allows operational flexibility. The packers are typically set in the bounding shale or sand. To accommodate a multilayer coal seam with varying thickness and typical washout in the bounding shale, several wireline trips may be required to change the tool configuration and distance between the packers at surface. Previously run openhole logs such as dual-axis caliper, acoustic/resistivity borehole imaging, advance dipole sonic, and 3D induction resistivity are used for the coal seam selection and packer positioning.

Conducting a WFT productivity test in a low-permeability coal seam provides atypical challenges from conventional oil and gas applications. The method was tested using field data and pressure transient analysis from six CBM wells in eastern and central Kalimantan of Indonesia.
Step Change Technology Amplifies Vertical Force Applied to Formation at the Bit Enhancing Cutting Efficiency
Authors: Herrington D. , Barton S. P. , Powell S. W.
Published: October 2013

Drilling efficiency is a key factor in determining the viability of potential hydrocarbon plays throughout the world. Pushing our capabilities for speed and accuracy changes the evaluation of value that not only operators place on emerging and potential plays, but also the evaluation that countries place on the value of their available natural resources. Fundamental drilling challenges such as formation hardness, reactive torque, tortuosity, and abrasive formation types continue to inhibit our ability to seek out less conventional reserves.

Reaching our targets faster and at a reduced overall cost allows us to expand the breadth of viable drilling opportunities in all regions while accessing additional value previously out of reach in existing plays. Today we are pushing current technology to the threshold of its capabilities with longer laterals and deeper targets in more complex well profiles. Without a step change in technology, we are nearing our maximum potential.

A simple yet revolutionary technology has added new life to existing drilling technologies and is now addressing some of the fundamental drilling dynamics that currently limit our drilling efficiency and restrict our ability to reach for the next level of performance. This technology works in conjunction with existing drilling systems to amplify the vertical forces applied to the bit. By varying this amplification at specific frequencies, more efficient failing of the formation can be achieved. Increased ROP well above 50% has been achieved with consistent results over offset data with reduction in reactive torque and stick slip events.

This paper details how by increasing cutting efficiency, a major operator has greatly extended bit life resulting in an increase in interval drilled lengths of as much as 125%.
A Case Study: Steamflooding to Enhance Recovery of a Waterflooded Light-Oil Reservoir
Authors: Shuhong Wu , Yu Qian , Dehuang Shen , Zhongyi Zhang , Xin Zhao , Qiaoyun Li , Hailong Liu
Published: October 2013

Steamflooding in heavy-oil sands is well documented as a mature technology, and while steam has been injected into light-oil low-permeability sands for almost as long, the mechanisms and effectiveness of this process are much less understood because of flow complexities in these sands and complexities of high-pressure steam injection. The full-length paper details the examination of thermal recovery in such a reservoir by use of physical and numerical simulations.

Steamflooding can improve upon performance of a waterflooded light-oil reservoir and enhance its oil recovery. The mechanisms such as wettability alteration, interfacial tension, and threshold-pressure-gradient decline contribute to higher oil displacement and sweep efficiency. Vaporization, viscosity reduction, thermal expansion, and relative permeability variation account for more than three-fourths of the incremental recovery in steamflooding.

The steamflooded light-oil reservoir in this paper is a low-permeability reservoir with a high wax content and high oil viscosity around 50 mPa.s. It underwent more than 10 years of waterflooding with only 10% of the original oil in place (OOIP) recovered from the reservoir. Challenges faced in this complex project were related to the heterogeneous nature of the reservoir, limited sand continuity, unfavorable mobility for the ongoing waterflooding, associated high threshold-pressure gradient, and poor injection response. The steamflooding was carried out to enhance oil recovery after waterflooding.

The paper discusses the mechanisms, strategies, barriers, and difficulties of reaching high recovery for steamflooding in a waterflooded light-oil low-permeability reservoir. A detailed reservoir-engineering study focused on the development method, the injection and production system, and the physical and numerical simulation.
Development Strategy for Thin Limestone Reservoir- A Case Study of AD Oilfield in Iraq
Authors: Limin Zhao , Qiliang Bo , Dandan Hu , Rui Guo , Mignsheng Feng , Jun Wang
Published: October 2013

Development strategy is the key issue and the lifeline for the short-term and long-term production of oilfields. It directly entails the success or unsuccess on the oilfield projects. So it is extremely essential to make the accurate development strategy, especially for an unproduced oilfield. AD oilfield, located in the southeast of Iraq, was discovered in late 1970’s and has been re-activated since 2009. The major target reservoir is Cretaceous Khasib II carbonates and this layered reservoir is distributed in the full field with an average thickness of 20m. The appropriate development strategy is the first priority to formulate for AD oilfield to ensure high oil productivity and long plateau duration.

In this paper, studies on the development strategy of Khasib II carbonates are elaborated. Individual well productivities before and after stimulation were analyzed and the average productivity was estimated for future development wells. The sensitivity studies of well types, well patterns and well spacings were carried out through sector model. Water injection feasibility and water injection timing were evaluated. Field development scenarios were described for Khasib II through full field modelling. Recommendations for the optimal development plan are made which indicates that the ultimate recovery factor is estimated to be 35% by water flooding. AD oilfield was put on production in June, 2011. The implementation of development strategies shows the good match between the actual and the predicted production indices.
Influences of Timeline and Perceived Strategy Effectiveness on Balanced Scorecard Performance Evaluation Judgments
Authors: Johnson Eric N. , Reckers Philip M. J. , Bartlett Geoffrey D.
Published: October 2013

This study examines evaluator ratings of subordinate performance in implementing a new corporate strategy in a Balanced Scorecard environment. We focus on two factors predicted to influence strategic performance judgments: (1) the presence or absence of an explicit timeline for strategy implementation, and (2) the evaluator's perceptions of the effectiveness of the new strategy. One hundred eleven M.B.A. students averaging over eight years of work experience participated in the study. Consistent with predictions, we find that (1) absence of an implementation timeline was associated with fixation on lagging financial performance measures outside of the subordinate's time span of control, and (2) evaluator perceptions of the strategy's effectiveness were positively associated with evaluations of strategy-congruent performance. These results extend prior research by highlighting the importance of the time dimension and perceptions of strategy effectiveness in performance judgments. Implications for future research in strategic performance evaluation are discussed.

Data Availability: Contact the authors.
The Effect of Light-curing Access and Different Resin Cements on Apical Bond Strength of Fiber Posts
Authors: Daleprane B , Nemesio de Barros Pereira C , Oréfice RL , Bueno AC , Vaz RR , Moreira AN , Magalhães CS
Published: October 2013

Purpose

This study evaluated the effect of light-curing access on the bond strength of fiber glass posts to the apical area of bovine roots using self-adhesive cement or dual-cured cement with an etch-and-rinse adhesive system.

Materials and Methods

The root canals of 60 bovine teeth were endodontically treated and filled. A 15-mm-length post space was prepared and roots were randomly divided into three groups, simulating the levels of light-curing access: coronal (C), with 15-mm post space; middle (M), in which the coronal thirds of roots were cut out, leaving a 10-mm post space; and apical (A), in which the coronal and middle thirds of roots were cut out, leaving a 5-mm post space. Fiber glass posts (Reforpost # 3, Angelus) were cemented with RelyX U100 (3M ESPE) or RelyX ARC/Scotchbond Multi Purpose Plus (SBMP) (3M ESPE) (n=10) and light-cured. After 24 hours, the apical thirds of roots were sectioned perpendicularly to the long axis and submitted to a push-out test (0.5 mm/min, 200 N). The Kruskal-Wallis test compared the three levels of light-curing access, and the Mann-Whitney test compared the cements.

Results

The bond strength was significantly higher in the groups C (p=0.028) and M (p=0.016) when U100 was used, whereas it was similar for both cements in group A. The bond strengths of posts cemented with ARC/SBMP were significantly higher in group A compared to group C (p=0.031).

Conclusions

The type of cement used and the light-curing access level influenced the bond strength between glass fiber posts and root canals. The bond strength of the RelyX ARC/SBMP cement proved to be more dependent on photoactivation than was the RelyX U100 cement. The light-curing access level did not influence the apical bond strength of RelyX U100.
Bounds on Capital Requirements For Bivariate Risk
with Given Marginals and Partial Information on the
Dependence
Authors: Bernard Carole , Liu Yuntao , MacGillivray Niall , Zhang Jinyuan
Published: October 2013

Nelsen et al. [20] find bounds for bivariate distribution functions when there are constraints on the values of its quartiles. Tankov [25] generalizes this work by giving explicit expressions
for the best upper and lower bounds for a bivariate
copula when its values on a compact subset of [0; 1]2
are known. He shows that they are quasi-copulas and not
necessarily copulas. Tankov [25] and Bernard et al. [3] both
give sufficient conditions for these bounds to be copulas. In
this note we give weaker sufficient conditions to ensure that
both bounds are simultaneously copulas. Furthermore, we
develop a novel application to quantitative risk management
by computing bounds on a bivariate risk measure. This can
be useful in optimal portfolio selection, in reinsurance, in pricing
bivariate derivatives or in determining capital requirements
when only partial information on dependence is available.