bluuebunny/crossref_metadata_2025_split huggingface dataset:
"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

Abstract
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

Abstract
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

Abstract
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

Summary
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.