bluuebunny/crossref_metadata_2025 huggingface dataset:
The Development of Material Balance Equations for Coalbed Methane Reservoirs
Authors: Firanda E.
Published: January 2012

This paper presents the development of material balance equations (MBE) for coalbed methane (CBM) reservoirs. This method is appropriate for determining Original Gas In Place (OGIP) and predicting fluid mechanisms in coalbed methane reservoirs. Previously, material balance for coalbed has been developed by G.R. King and several researchers. King’s MBE has considered water expansion, rock (cleat) compaction and water influx. In this paper, author added some new aspects such as gas expansion, water connate expansion, moisture expansion, rock (matrix) compaction and also modified King’s p/Z*. Author also explained the derivation of average water saturation equation that hasn’t been explained before. The author used actual data to validate the equation and the results were compared with King’s MBE results. These comparisons are used to determine the magnitude effects between these equations. The proposed material balance provides more accurate results and more options of variables which can be considered and applied as a new equation for simulation.
Advanced Technologies and Practical Guidelines for Challenging Drilling Applications
Authors: Jellison Michael , Chandler R. Brett , Sanclemente Leianne
Published: January 2012

Critical wells exceed the capabilities of S-135 drill strings. Drilling teams are evaluating advanced technologies to expand the drilling envelope. The paper details the development of ultra-high strength UD-165 drill pipe, provides comparisons with S- 135, Al and Ti drill pipe and provides field trials summaries. New developments are necessary to drill and complete deeper and longer-reach wells. Rotary shoulder connections offer significant advantages when coupled with high-pressure seal technology for completion pipe and intervention risers. The paper provides details on critical applications that benefited from new connection technology.

With water depths over 10,000 ft, well depths exceeding 34,000 ft, and extended-reach targets over 35,000 ft, operators are setting larger diameter and heavier casing. These casing strings require landing strings with setting capacities approaching 2.5-million pounds that extend the limits of tubular manufacturing and handling capabilities. The paper describes the technology advancements required to develop and implement an ultra-high capacity landing string system. A 6-5/8 in. drill pipe based riser system for offshore completion and intervention work has been successfully used for several years. The primary advantage of the drill pipe based system relates to the rotary shoulder connections (RSC). RSC makeup and breakout quickly, are rugged, and are superior at resisting galling and handling damage compared to casing connections that are often used for risers. The use of these intervention risers in sour gas areas has been prevented because there were no fully Sulfide Stress Cracking resistant tubular systems with RSC. This paper presents the successful result to develop and qualify an SSC resistant friction weld for intervention risers. Industry advancement has led to an increasing trend of drill stem downhole friction heating failures. The paper includes characteristics of these failures with case histories and prevention methods.
Development of New Sand Consolidation Fluid and Field Application in Shallow Gas Reservoirs
Authors: Fuller Michael J. , Gomez Ricardo A. , Gill Joel , Guimaraes Cesar , Abdurachman Ardestya Ferta , Chaloupka Vladimir , Descapria Rio
Published: January 2012

Extensive laboratory testing was conducted to qualify new internally catalyzed consolidation system. The tests were conducted both using sand packs and core samples and were to measure post treatment compressive strengths, regained permeabilities, rheological properties and working time of the fluid. The results of the above tests are presented as well as fluid field trials performed in shallow gas reservoirs in Tunu giant gas field located in the Mahakam river delta in the province of East Kalimantan, Indonesia.

The development of the fluid and its field application were driven by the search for an effective alternative to conventional primary sand control methods that would allow developing marginal reserves where the conventional methods might not be economical. Unconsolidated sand packs treated with the new consolidation fluid led to high compressive strengths and regained permeabilities. The tests performed on Tunu core samples showed similar improvements in unconfined compressive strength (UCS) and regained permeability. This was despite the fact that these formations can have very undesirable properties for sand consolidation as per common industry belief with high shale content up to 25 % and d50 of formation being as low as 30 μm.

Two treatments were successfully performed on shallow unconsolidated layers using coil tubing. The reservoirs produced at gas rates up to 2.8 MMscfd and 4.0 MMscfd sand free.

The new consolidation fluid was successfully qualified through a series of core flooding tests and field tests. As opposed to the comparable products currently available on the market, the fluid has low flammability rating significantly improving the safety aspects of the treatment. The treatment using this new consolidation system showed that it can provide a viable primary sand control option for developing marginal gas reserves.
Effect of Alkalis on Phase Behavior of Mixtures between Single and Double Tail Anionic Surfactants
Authors: Nguyen Ngoc T. , Bae Wisup , Dang Cuong T. , Ryoo Won , Lu Vi D.
Published: January 2012

Alkaline–Surfactant–Polymer (ASP) flooding is considered as a promising method for enhanced oil recovery since 1980’s. Even though the concept of ASP is straight forward, but it is a very complicated process due to complex of chemical slug. Moreover, the success of ASP is mostly demonstrated in laboratory conditions; thus, it is necessary to investigate this process in hostile reservoir conditions for achieving a wider and successful implementation. This paper presents a comprehensive evaluation of the phase behavior of ASP systems, which is successful, the key of ASP process in high temperature reservoir.

The experimental results prove that the mixtures of single tail anionic surfactant and double tail anionic surfactant would be adequately overcome the challenge of high temperature condition of reservoirs. These mixtures are also more compatible with polymer and increase the optimum salinity. In other words, the developing of new advanced surfactant mixture allows apply ASP flooding in high salinity reservoir.

Next, we examine the important role of alkaline in ASP process. Three alkalis such as including sodium carbonate, sodium metaborate, and sodium metasilicate were tested in phase behavior experiments at high temperature condition (90°C) for both synthesis (dodecane) and crude oils. The results indicate that alkaline in the ASP systems can react with some acidic components of the crude oil to form in-situ surfactant, which then would help lowering the IFT between oil and water phases. It reduces the cost of process because alkaline is cheaper than synthesis surfactant. Besides alkaline also affect on interfacial tension and phase behavior of ASP systems.
Optimal Placement of Horizontal Wells in Ultra-High Resistivity and Stacked Channel Sandstones: A Case Study from the Mangala Field, Rajasthan, Western Onshore India
Authors: Singh Amit Pal , Mishra Sumit , Tandon Rohit , Majumdar Chandan
Published: January 2012

The Mangala Field is the largest discovered oil field in the Barmer Basin of Rajasthan, India with a STOIIP of over 1 billion barrels contained in stacked clastic fluvial reservoirs of the Fatehgarh Formation (Compton, 2009). The Fatehgarh Formation is divided into two broad reservoir units. The upper Fatehgarh (average net to gross ~40%), consists of low sinuosity channel system sands, and the lower Fatehgarh, consists of 30m to 40m of stacked braided fluvial sands (average net to gross ~90%) having resistivity of more than 5000 ohm-m.

The flow simulation model demonstrated that horizontal wells are the best way to develop the lower Fatehgarh reservoirs. The key challenges in successful drilling of horizontal wells are the uncertainty in formation top, the position of field bounding fault, presence of gravitational collapse faults, and navigating within the ultra-high resistive reservoirs.

Offset well correlation, high resolution sampling of drill cuttings, close monitoring of grain size variations and real-time density image log analyses were used to overcome the challenge of landing the well in target reservoir zone at desired borehole inclination. After landing the well, the strategy was to build borehole angle to ~90° and geosteer within the reservoir zone. The directional resistivity tool used is sensitive to resistivity contrasts providing an early indication of non-reservoir ahead of bit. However the ultra-high resistive reservoirs limited the boundary detection capability of this tool thus reducing the reaction time to take corrective measures. The true stratigraphic position (TSP) of the wellbore was also continuously monitored using gamma ray correlation.

Eleven horizontal wells have been drilled in the Mangala field using various data integration approach. Accurate placement of wells in the best part of the reservoir, avoiding interlayer mudstones, has resulted in more than 90% reservoir contact and an average production of ~10000 bopd/well.
Natural Gas Reserves in the Middle East and India as its Market with Promising LNG Technology for Transportation
Authors: Unni Vaisakh S.
Published: January 2012

The share of Natural Gas in global energy consumption has grown steadily and will continue to rise for the years to come. Forecasted supply of compromised natural gas is in the year 2050 to be 115-120 x 109 toe or 13.4-14% and 228 x 209 toe of remaining ultimate reserves or 12% of the total. Of the world’s two major natural gas provinces, the largest (Russia) is being exploited, while the other (The Middle East) is still rather untapped-hence its bearing on future gas supplies. India with its radiant market and high GDP growth rate promises to provide huge customer base for natural gas industry. Study on natural gas market in India is made in this paper. The paper gives a look into the opportunities arising out of the policy initiatives taken by the Government of India which are welcoming, though skewed development of the market due to regulated market pricing may be deterrent.

Liquefied Natural Gas (LNG) technology is used for natural gas transportation for long distances. The development and implementation of technologies in this field have led to significant growth in worldwide LNG business. Lessons learned in design, implementation and execution of large LNG carriers(trains and ships), as well as overall changes of LNG liquefaction trains in last twenty-five years, have been key to evolving design of LNG value chain.

This paper concentrates on natural gas reserves of Middle East and its potential of becoming the main supplier for the future, natural gas market in India, potential and limitation of gas supply scenario in India and LNG technology for transportation and its challenges in future.
Two-Phase Flow Choke Performance in High Rate Gas Condensate Wells
Authors: Nasriani Hamid Reza , Kalantariasl Azim
Published: January 2012

Multiphase flow occurs in almost all producing oil and gas/condensate wells. Wellhead chokes are special equipment that widely used in the petroleum industry to control flow rate, to maintain well allowable, to protect surface equipments, to prevent water and gas coning and to provide the necessary backpressure to reservoir to avoid formation damage from excessive drawdown. Accurate modeling of choke performance and selection of optimum choke size is vitally important for a petroleum engineer in production from reservoirs due to high sensitivity of oil and gas production to choke size. Two main approaches have been proposed for prediction of multiphase flow through chokes can be classified as either analytical or empirical and majority of correlations were developed for critical flow conditions.

Although most of the correlations available to petroleum engineers are for critical flow but in lots of high rate gas/condensate wells subcritical flow occurs in large choke sizes.There is no empirical correlation for wellhead choke performance under subcritical condition for high rate gas condensate wells, especially in large choke sizes. The first aim of this paper is to develop a new simple empirical Gilbert type correlation for high rate gas condensate wells under subcritical flow in large choke sizes (40/64 in. to 192/64 in.) using non-linear regression analysis based on 61 field data points of 15 wells from ten different fields. The second is to extend the work of Al-Attar for high rate gas condensate wells flowing through large choke size under subcritical flow conditions and check the applicability and advantages.Finally, statistical comparison between these two approaches is done with different error parameters.
Flow Model Selection for Production Logging Interpretation of Gas Wells
Authors: Jongkittinarukorn Kittiphong , Kerr Robert
Published: January 2012

Water production from gas wells is a major issue in the Gulf of Thailand. Production Logging (PL) is the main way to try to discover the water source and hence shut it off. Sometimes there are clear indications of water entry such as density increases and holdup sensors showing more water entering the flow. For many wells, though, there is no clear water entry and the water rate is a result of the calculations that are very dependent on slippage velocities derived from various flow models. Emeraude from "Kappa Engineering" (Kappa from now on) allows the use of any one of ten different models to derive the slippage from. The problem is that there is no clear way to decide which model is best and the effect on the results of using different models is significant, often moving the water split between zones.

This study uses the surface rates to compare with the rates calculated from the PL data using each of the ten different models. Some 300 PL cases are used to allow a statistical analysis to determine the most precise, accurate with minimum error, models. The best three from this statistical approach go forward to a Discriminant Analysis where the critical factors which governed when a model works best are ascertained. Then the Fischer Discriminant Functions could be calculated for these three models so that this could be used to select which model to use for future Production Log Analysis.

The study comes up with a systematic way to select which model to use. It found the models that were not typically being used in the past should be used so this was quite a big change. The logic was applied to some past PL examples and the recommended models are found to give results more consistent with known shut-off's that the original analysis had done. The method seems to have value and should improve the effectiveness of future water shut-off actions though the number of wells the study has been applied to is small and time will allow further verification of the technique.
Research on Transport of Cuttings in Gas Drilling Horizontal Well and Cuttings Falling-prevent Joint Development
Authors: Zhu Xiaohua , Liu Shaohu , Tong Hua
Published: January 2012

Field experience has shown that inefficient transport of cuttings is a key factor for excessive torque & drag during gas drilling of horizontal well. Therefor, the focus on the transport of cuttings or the hole cleaning operation during gas drilling is essential. The cuttings tend to deposit themselves due to gravity's action, so forming a bed in the annular space between drill string and casing. If the cuttings bed isn't cleaned in time, it may cause the sticking accident, fluid flow interruption, drill string and casing erosion, finally it leads to the economic loss. Transport mechanism of cuttings during gas drilling has been studied based on gas and solid two-phase flow dynamics theory in different annular section of horizontal wellbore. The involved annular sections includes normal well, eccentric annular section formed by the drill string lying on the underground level of casing, diameter enlargement annular section. This paper presents a new tool for improving the cuttings transport efficiency during gas drilling. This tool is named cuttings falling-prevent joint (CFPJ) which has a split-flow nozzle. The structural parameters of split-flow nozzle, such as opening gradient, opening azimuth and nozzle linetype, which influence the CFPJ's sweeping and carrying capability, were studied using computational fluid dynamics technology. The study shows that changing CFPJ's structure parameters can adjust the radial, tangential and axial sweeping & carrying capability, and finally the recommended CFPJs can solve cuttings' falling problem in gas drilling horizontal well.
Produced Water Treatment Improvements in Facing Indonesian Government Regulation on Onshore Disposed Waste Water
Authors: Trusmiyadi Yadi , Kurniawan Farid , Fitria Rila , Elias Esther , Muhyinsyah Ahyat
Published: January 2012

Produced water is the largest byproduct generated by the oil and gas industry. Water injection, considered as the best answer for produced water disposal, is not always possible due to reservoir constraints. The secondary produced water treatment facility in Mutiara Central Plant, VICO Indonesia, is a phenol treatment plant (PTP). It is processing approximately 8000 BPD produced water before being released to the Dondang River. A biologically activated sludge process is applied to reduce the pollutant content so the disposed water complies with onshore waste water disposal regulation for oil and gas production industry on Permen LH 04/2007. The process reduces chemical oxygen demand (COD), ammonia, phenol, sulfide, and oil and grease content in the produced water. Frequently since 2008, high COD and ammonia content above the regulated thresholds (200 mg/L for COD and 5 mg/L for ammonia) in disposed produced water has been observed.

A field investigation was conducted to collect integrated data of recent process parameters. The field data were then compared to design conditions, industrial practices, and literature to a determine root cause tree. In addition, a feed batch activated sludge pilot was constructed and study on inlet COD source was performed for comprehensive study.

The field investigation revealed that root causes limiting the phenol treatment performance were higher oil content and COD in the inlet stream, highly fluctuating inlet debit, lack of oxygen supply, and inadequately designed and maintained clarifier and return sludge system. Following minor mitigation actions in January 2010 such as chemical process optimization, adjusting nutrient doses, adding sugar, fresh microbes, and routine maintenance, the effluent quality data has improved to just bellow the threshold. Six major improvements were proposed to improve PTP performance and effluent quality; e.g. repair pre-heater, construct new secondary clarifier, replace existing return sludge pump with proper capacity, install three more aerators, utilize K1 as equalization pond, and repair existing drying bed. VICO Indonesia has committed to commissioning the first four recommendations by the end of 2011.
Field Development and Water Flood Management in Complex Clastic Field in Oman – Case Study
Authors: Al-Harrasi A. , Rathore Y. , Kumar J. , Maharbi A. , Shukaili S. , Al-Subhi H. , Al-Salhi M.
Published: January 2012

X-field located in the west Central Oman is in a mature stage of development from the Permian Gharif formation reservoirs. These stacked reservoirs have been historically produced commingled since 1984 with natural depletion until 1998. Since then the field is under water flood. Produced water is mainly re-injected and gas is used for gas lift and the rest is liquefied and exported.

The need for effective pressure maintenance was recognised only when the field pressure depleted under primary development and GOR increased. The FDP proposes peripheral injection in the NW due to better sand connectivity and pattern injection in areas of low sand connectivity. The artificial lift mechanisms are a mix of ESP and Gas lifted wells.

Water flood management is highly challenging in this complex and heterogeneous reservoir. Water front conformance causes challenges with impact on vertical and horizontal efficiencies. The reservoir sands that are not supported by water injection have issues with wax and scale deposition in the producers. The field separation facilities are constrained by gas handling design capacity. Future challenges are expected with well and flow line integrity issue due to the gaining facilities.

Despite all challenges, the water flood is actively supporting production in most areas. Surveillance is the key to managing this complex waterflood. Additional drilling is used for further development with well and reservoir management practices to target by-passed oil, improve water flood efficiency and increase oil production. The surface and sub surface integrated system optimization is helping stabilize the system and delivering improved oil production and gas export with ongoing implementation of new artificial lift strategy.

This paper documents a case history of waterflood management in X-field and the challenges that have to be overcome.
A Comprehensive 3D Thermo-Chemo-Poroplastic Model for Evaluation of Borehole Stability in Chemically Active Rocks
Authors: Roshan H. , Oeser M.
Published: January 2012

Several instability issues such as pipe sticking, washout and borehole collapse can be experienced during drilling in chemically active formations. The conventional approaches towards the geomechanical modeling of such formations fall short of describing complex behavior of chemically active rocks, such as the swelling shales. The effect of crystalline swelling and chemical osmosis on elastic deformation have been adequately addressed by many authors, however, the effect of these changes on plastic deformation of rocks under three principle stress conditions have not been investigated. In this paper the effect of hydration/dehydration due to thermal and chemical osmosis on plastic deformation of chemically reactive shales is studied.

The 3D-model is developed to evaluate borehole stability problems in drilling a troublesome shale formation. From the results of this study it was revealed that most reactive shales at typical drill depth (2500m to 3500m) undergo plastic deformation. Hydration/dehydration due to crystalline swelling and osmosis (chemical and thermal) further aggravates the mechanical properties of shales. The numerical experiments also show that the vertical stress plays a significant rule in formation of plastic zone around the wellbore thus, making the wellbore prone to collapse failure.
Utilization of High Value Engineering Center (HVEC) in Execution of a Major Capitol Project, Gorgon
Authors: Malladi Siva , Shah Parag , Cruikshank David
Published: January 2012

The Chevron-operated Gorgon Project is located off the north-west coast of Western Australia and encompasses a number of mega-projects including an all-subsea upstream development of the Greater Gorgon gas fields, a greenfield gas processing facility including a 15MTPA liquefied natural gas plant and a 300TJ/d domestic gas plant and the world’s largest commercial scale carbon dioxide injection project.

The Gorgon Project is operated by an Australian subsidiary of Chevron and is a joint venture of the Australian subsidiaries of Chevron (approximately 47 percent), ExxonMobil (25 percent) and Shell (25 percent), Osaka Gas (1.25 percent), Tokyo Gas (1 percent) and Chubu Electric Power (0.417 percent).

Due to its sheer size, scale and complexity, in addition to a number of unique characteristics, the Gorgon Project has required an extraordinary level of project management and one of the key project management strategies employed has been the appointment of a High Value Engineering Center (HVEC) in Jakarta.

This paper explores the benefits of using the HVEC concept; the evaluations performed on the HVEC; the challenges associated with the execution; the execution planning utilized and the tactics utilized in executing the work, which have all enabled the successful delivery of the engineering phase of the Gorgon Project.

The HVEC concept is not new to the oil and gas industry. But execution success tends to vary based on numerous criteria and variables associated with the HVEC centre.

The conclusion is that the HVEC concept works and has a place in the execution of Major Capital Projects. The concept can be very successful with the following in place: Thorough evaluation of the HVEC capabilities, with a feed back into the HVEC execution plan.The HVEC project execution receives appropriate oversight from the main Execution Center (EC).Highly competent and motivated management present at the HVEC level.Robust procedures and processes in place to provide required guidance to the HVEC personnel.A detailed HVEC execution plan and implementation of the execution plan.Transition of the work scope from the main EC to the HVEC in accordance with the execution schedule, at an adequate level of maturity.

Although the HVEC concept is not new to the oil and gas industry, execution success tends to vary based on numerous criteria and variables associated with the individual HVEC utilized, its experience and its relationship with the managing EC.
Real-Time Optimization of an Integrated Gas System
Authors: Göbel Derek , Cramer Ron , Briers Jan , De Boer Frank , Lai Kok-Lam , Hooimeijer Martijn
Published: January 2012

This paper describes the large-scale trial of Real-Time Optimization (RTO) that Shell Malaysia E&P has conducted on the Integrated Gas Production System iln Sarawak, implementing models for real-time monitoring and optimization of wells and facilities on a gas production network spanning more than 100 wells on more than 40 platforms across a number of different Production Sharing Contracts (PSCs). We highlight how Digital Oil Field (DOF) practices enable field-based data to be turned into information, support decision making, and lead to actions that ensure production is optimized continuously.

The technology described in this paper is applied to achieve consistent gas supply to meet demand, maximizing revenue on producing assets, and enabling improved and timely operational decisions - striking a balance between short-term revenue and long-term value. It demonstrates Shell's ability to manage and continuously optimize complex, integrated, multiple-objective, closed-loop systems such as gas production assets. The pursued benefits are increased condensate production at current or improved expected Ultimate Recovery, whilst maintaining a stable gas supply, fulfilling quality constraints and contractual LNG nominations.

The optimization is data-driven and covers more than 1,000 variables and features multiple, mutually dependent objectives and constraints. The solution has proven significantly better than prior physical model-based solutions, which are capable of delivering optimized field settings, but with inherently unstable results, and not fast enough for application in a real-time decision making environment. This is one of the first successful attempts to optimize, in real-time, a production environment of this size and complexity, including a complicated set of commercial and contractual constraints.

Additionally, this approach replaces the traditional, daily or monthly optimization by a continuous one. The system generates optimal set-points for the control variables which are executed by the operators. Closed loop control is possible with remotely operated chokes which would allow the optimization of the entire gas system to be fully automated and minute-by-minute.
Heavy Oil Recovery by Steam Injection, Mapping of Temperature Distribution in Light of Heat Transfer Mechanisms
Authors: Romanov A. , Hamouda A. A.
Published: January 2012

Enhancing heavy oil mobility and drainage induced by reduction of viscosity and density due to temperature increase caused by steam injection is one of the most used methods by the industry. In spite of the vast investigation done in literature for the area of steam injection, the mechanism(s) of heat flow in reservoirs are not fully understood. Understanding heat flow mechanism(s) and temperature distribution, contribute to better optimization of the used steam.

It is attempted in this paper to shed light on thermal recovery and temperature distribution with steam injection from experimental work. Basically, a model reservoir is constructed with heavy oil to be recovered by steam injection. Mapping of temperature propagation within the model reservoir clearly demonstrates fast steam/ temperature propagation to the overburden and then propagate horizontally at the top of reservoir. Hence, top of the reservoir becomes the second heating source of the underlying layers. However, the obtained temperature propagation profiles of simulated heavy oil thermal recovery by steam are different from the experimental data.

Analysis of the temperature distribution shows that at the interface between the heated and cold region of the reservoir are initially contributed by convective heat flow (steam condensate and mobile heavy oil), then conductive heat transfer dominates. As the temperatures reach / close to steady state in the different heated areas, maximum drainage process takes place.

Different simulation and experimental temperature distribution data are compared and showed better agreement between the estimated and experimental data as a function of time, indicating more conductive heat transfer mechanism with time.

It is interesting to observe that in spite of the complexity of different processes taking place, consistent temperature gradients are established within the reservoir. This could lead to a better optimization of steam injection regime.
Confidence in Data Aids Improved Asset Value
Authors: Palmer Gregory A.
Published: January 2012

Twenty-first-century oil and gas operations are facing a unique set of challenges that require new workflows and processes, and new ways to leverage technology. The objective is to help petrotechnical professionals manage huge volumes of data to improve understanding and analysis, and support sound decision making—with an ultimate goal of improving asset value.
Fibrous Organic Cellulose Application to Combat Seepage Losses in Fractured Limestone Formations, Offshore East Kalimantan, Indonesia
Authors: Taufik M. , Panjaitan R. A. , Djambek A.
Published: January 2012

XY fields in offshore East Kalimantan, Indonesia, have a history of whole drilling fluid losses ranging from continuous seepage to catasthropic losses in its "high amplitude carbonate body". Even though these carbonates are well known and documented, have been closely predicted and well anticipated, and drilling program account for their occurrence, whole drilling fluid losses continued to plague drilling operations and result in highly cost of drilling fluid losses, require expensive treatments and incur Non-Productive Time (NPT)

Drilling programs call for controlling Equivalent Circulating Density (ECD), matching Rate of Penetration (ROP) to hole cleaning efficiency and reducing surge and swab pressures when loss zones are expected. Standard Lost Circulation Materials and Loss Prevention Materials (LCM and LPM) had been previously prepared and pumped prior to entering the loss zones with unpredictable and less than desirable results.

A special, Indonesia-sourced and manufactured, patented organic cellulose fiber was introduced in the fluid system to prevent losses prior to drilling the troublesome formation. A rapid, inexpensive, easily understood and applied, field test procedure have also been introduced for further development which allows a quick and accurate assessment of fluid system permeability sealing effectiveness and avoid over-treatment with fluid additives due to treating "on schedule" or "by formulation".

A significant improvement was shown for the first trial on X107 well and also on one exploration well. Success was achieved due to the ability of the Lost Prevention Material additives to create an effective wellbore seal in the troublesome formations. Drilling was continued without incurring NPT due to drilling fluid losses or remedial treatment requirements.

This paper presents and describes case histories which will detail material types and grades, function of the patented material, specific application and treatment details and compare time and cost savings to offset wells.
Integrating Mini-DST-Derived Permeability With Other Sources: A Case Study
Authors: Harmawan I. , Kabir C. S. , Habib S. , Kennedy J. , Henson J. , Minhas H.
Published: January 2012

Permeability is the cornerstone to any reservoir-flow modeling, leading to field development and production management. Typical sources of permeability include cores, logs, wireline formation tests or mini-DSTs, and conventional drill-stem tests or DSTs., Integrating various sources of permeability at different scales is problematic. Anchored in mini-DST-derived permeability, this study endeavors to integrate various sources of permeability, leading to reservoir description in a trubidite sandstone reservoir in the Sabah Basin, Malaysia.

Pressure-transient test data recorded during a mini-DST operation differ significantly from those gathered during a conventional DST. In the case of this well, although the test quality is excellent, interpretation challenges are numerous. The paper llustrates the planning and integration of Mini-DST data with multidisciplinary information from side-wall cores, MDT, NMR, and FMI image logs. This case study demonstrates that, in this particular setting, the use of mini-DSTs was cost-effective and yielded the necessary subsurface information required to plan field development options.
Correction of non-Darcy Coefficient and How to Estimate It for Development Wells
Authors: Raijo Tsuyoshi
Published: January 2012

Abadi gas field located offshore Arafura Sea, eastern Indonesia (Figure-1) was discovered by INPEX in 2000 and the appraisal activities have been carried out subsequently since then. Total 7 wells have been drilled and 8 DSTs have been conducted so far. The objectives of this work are to obtain more accurate non-Darcy coefficient (D) from the exploration and appraisal well’s Drill Stem Test (DST) by accounting for the completion effects, and to estimate D for the development wells.

The result shows the importance of accounting for the completion effect in order to get more accurate non-Darcy coefficient (D). The installation of the downhole gauge below packer & flow sub eliminates the need for this kind of correction.

It was confirmed that the completion effect can significantly underestimate the IPR (Inflow Performance Relationship) of the high-permeability gas wells. In addition, the turbulence coefficient β was found from the field data to be the function of not only the reservoir properties but also the gun specification. To use a deep penetration gun and to avoid partial penetration were found to be the key for reducing the pressure drop caused by non-Darcy flow, if the cased & perforation is adopted as a completion technique of the development wells for the reservoir of interest.
Implementation of Next Generation Intelligent Downhole Production Control in Multiple-dipping Sandstone Reservoirs, Offshore East Malaysia
Authors: Chen J. H. , Azrul N. M. , Farris B. M. , NurHazrina K. Z. , Aminuddin M. K. , Saiful Anuar M. Y. , Gordon Goh K. F. , Kaur K. S. , Luke T. K. , Eddep A.
Published: January 2012

The ‘S’ field, located offshore East Malaysia, consists of multiple-dipping heterogeneous sandstone reservoirs with unconsolidated formation. These multi-stacked reservoirs have an overall 40m thick oil column with marginal Oil-Initial-In-Place (OIIP). A large gas cap, i.e. twice the OIIP equivalent, also exists. Scenarios of zonal gas-out leaving huge oil bypass and moderate aquifer strength with inevitable water invasion cautioned the asset team to consider intelligent zonal flow control especially in its horizontal producing wells.

Two of the 14 horizontal producer wells in this marginal field have been screened to apply the modular integrated intelligent completions system (IICS) to actively control and permanently monitor zonal inflow for optimal production. Future selective production control and data surveillance enabled by the IICS are essential to fulfill the needs for delicate downhole zonal flow balance for ultimate oil incremental and recovery. It provides control against the aggressive gas cap expansion at the heels while addressing the moderate aquifer coning-up problems from the dipping toes as the field depletes.

This paper highlights the successful implementation of the next generation intelligent completions system in a complicated, highly-dipping, multi-layered sandstone reservoir with commingled production. In this multi-zonal production solution, the conventional surface-controllable downhole zonal flow control valves are now integrated with data surveillance gauges, intelligent sensors and isolation packers all into one single completion joint, instead of the precedent multi-joints system (i.e. splicing required up-to 3 joints per zone conventionally). This single modulated joint system has reduced installation time substantially in comparison to conventional intelligent completions installations. The risk of surface completions make-up damage before run-in-hole is also greatly reduced with less connecting components. This robust yet compact system has made on-site completions tally adjustment easier and is enabled with LWD data update while drilling. As a result, intelligent completions design becomes more flexible and responsive to actual reservoir challenges and drilling surprises – providing an all together "intelligent" solution.

This paper also discusses the screening process from simulation performed for candidate evaluation to the resulting impact on production post-installation. Future applicants of such technology with similar fields’ nature and risks can benefit from the discussed lesson-learnt; best-practice workflow and seamless teamwork and coordination between the project team and service providers in delivering an advanced fit-for-purpose solution.
Temporary Storm/Cyclone Well Suspension Using Inflatable Packer Systems
Authors: Ingram Colin
Published: January 2012

The official tropical cyclone season in Australia runs from November 1st to April 30th and in a normal season it is usual to expect an average of at least 10 cyclones to develop over Australian waters. They are particularly prevalent on the North West Australian coast where drilling activity, especially in deep water is currently ongoing. With the approach of a cyclone it is standard practice, as mandated by government regulatory bodies in the guidelines for offshore well operations (Ref. 1), to temporarily plug the well. These regulations call for temporary barriers to be installed in the well to provide the safety required when the rig is evacuated or, in the case of semi-submersible or floating rigs, disconnected from the well and even moved off location.

It is not uncommon with today’s drilling technology to use long large-diameter casing strings, such as 20" OD (508mm), to depths of as much as 2000m (6562ft), but the availability of matching hook wall packers to be used as temporary plugs is severely limited and, as a consequence, the provision of the contingencies for emergency suspension or abandonment of such wells can present a major operational problem. To address this situation a large diameter inflatable packer/bridge plug system has been developed which can be run and set in several different casing diameters and left in the hole as a bridge plug to hold pressure from below to fulfill the regulatory, and safe operating requirements, that are mandated.

In this paper the author will review the design and operation of this large diameter inflatable bridge plug and describe the running procedure and the setting, retrieving and fluid handling tools that are required for safe and reliable operation. The author will present a case history of the deployment of this system in the offshore North West Australia operational area in severe weather and cyclonic conditions.
Reservoir/Well Production Assurance Strategies for Successful Field Development Projects
Authors: Chan Keng Seng , Masoudi Rahim , Ataei Abdolrahim , Darman Nasir H. , Othman Mohamad B.
Published: January 2012

Wells drilled and completed following the approved field developed plan (FDP) may not yield satisfactory performance results as predicted at the FDP phase. The gap could be due to accumulation of various uncertainties and risks encountered in each phase of field development planning from reservoir characterization, flow dynamic properties, well reservoir penetration and production optimization, well design, drilling and completion, to well support surface facilities design and implementation.

This paper delineated the issues/challenges in each key task of field development planning focusing on three key areas for improving quality assurance in (1) reservoir simulation, (2) drilling and completion, and (3) production system. Real field example cases were used to illustrate the need to improve integration of pre-during-post FDP strategies and approaches. The paper also provides simple and short check lists on requirements and workflow for helping to assure FDP well production throughout the field life.
Walkaway VSP Aid in Well Location Selection in Mumbai High South India, A Case Study
Authors: Rana R. K. , Lim T. K. , Deo P. P. , Sundaram K. M.
Published: January 2012

Surface seismic imaging is one of the initial stages in oil and gas exploration. Low frequency content and unknown changes associated with surface seismic contribute to the limitations of low resolution and uncertainty in the processing of surface seismic.

The limitations of surface seismic images also cause uncertainties in interpretation that could lead to dry wells. High-resolution borehole seismic images illuminate the subsurface better and can add value to the interpretation. The advantages of borehole seismic surveys can also be found in the literature (Hardage B. 1983)

In this study, a case is presented in which low-resolution surface seismic was not appropriate to delineate the reservoir and led to a dry well for Oil and Natural Gas Corporation (ONGC). A walkaway vertical seismic profile (WVSP) was recorded to resolve the issues and help make decisions for the next well location. WVSP provided high-resolution images around the well that also suggested the subseismic faults in the area.
Integrated Strategy Delivers Secure and Fast Drilling in Deep CO2-rich Gas Reservoir in Volcanic Formation
Authors: Cheng Rongchao , Wang Haige , Ge Yunhua , Zou Lingzhan , Chen Zhixue , Zhang Fucheng , Li Hongsheng , Bi Wenxin
Published: January 2012

The great exploration discovery of natural gas resources in volcanic formations has uncovered a prospective prologue for tremendous development activity in deep Songliao Basin, China, which inherently contains a high CO2 concentration of about 14%-30%. The CO2-rich environment combining with the poor drillability of volcanic rocks has made operators confronting with challenges in drilling and completion operations, such as anti-corrosion against pipe string and set cement, optimization of casing program and bit type, ROP improvement, and cost effective UBD and multi-lateral drilling methods.

An integrated strategy was successfully proposed and deployed to address drilling related problems. Firstly, based on the analysis of wellbore stability and anti-corrosive mechanism under different downhole condition, the casing program and anti-corrosive scheme for production casing material were optimized for vertical well and horizontal well, respectively. Secondly, a new CO2 corrosion resistant cement slurry was developed using a new anti-corrosive material F11F and other anti-channeling HT agents. Thirdly, with respect to detailed study on CO2 invasion affection, reservoir sensitivity, scale building prediction and wellbore multi-phase flow mechanism, appropriate UBD drilling fluid and bottom underpressure value were determined. Then, the specific bit design method and gas drilling technology were jointly applied to enhance ROP in deep volcanic formations. Finally, matching technologies for horizontal and multi-lateral well operations were systematically modified considering the PDM (positive displacement motor) tool and geosteering method.

Favorable achievements have been obtained during years of continuous optimization of drilling scheme. The integrated strategy allows more secure and faster drilling in deep volcanic formations, and offers a tight foundation to maintain profitable production in Songliao Basin. This paper will highlight the technical development in the CO2-rich area, and present helpful case histories and recommendations.
Hydraulic Fractures Monitoring using Microseismic Techniques in Clastic Reservoir - A Pilot Test Case from India
Authors: Lim T. K. , Mishra S. , Gupta A.
Published: January 2012

Clastic gas reservoirs can be made economical through effective stimulation techniques. Hydraulic fracture mapping based on seismic techniques can lead to better understanding of the effectiveness of reservoir stimulation, when combined with in-depth reservoir geology and geophysical knowledge make development of such fields feasible.

Two stages, out of five hydraulic fractures stimulation were monitored and mapped in an attempt to assess the fracture propagation in a clastic gas reservoir located in Rajasthan, Western India. This was the first hydraulic fracture monitoring in India using downhole wireline sensors whereby recorded microseismic (MS) events indicating fracture growth as they are being created by rock failure. Events triggered by the stimulation treatment are detected and located in a four-dimensional (4D) space (space and time) relative to the well being treated.

The microseismic images indicate that fractures are well distributed within the Upper and Lower Fatehgarh formations, in the north-east south-west azimuth. The first monitoring was done on Stage-4 and recorded very few MS events, but indicated a relatively contained fracture. The fracture geometry estimated from the mapping matches closely with the parameters anticipated from the frac modeling work. The second monitoring was done on shallower Stage-5 and showed downward height growth during the initial stage of the treatment. This observation indicates that the hydraulic fractures may have intercepted a fault located within the treatment well. The result is being integrated with the planned stimulation model, mini-frac data, stress profile and other geological information. This will help in calibration of the stimulation model. Understanding of the fracture geometry from this technique along with the fracture geometry available from fracture modeling, well testing, etc. shall be combined to arrive at optimized designs for future fracturing campaigns in this clastic gas reservoir.