bluuebunny/crossref_metadata_2025 huggingface dataset:
An Integrated Pore-Pressure Prediction Approach: A Success Strategy to Develop Deep Gas Reservoirs by Drilling through a Highly Depleted Shallow Zone, Semberah Field, East Kalimantan, Indonesia
Authors: Jauhari Usman , ST Slamet , Anggraini Dayu Agung , Sinaga Iranta Bona , Widiastuti Bhakti
Published: January 2012

The Semberah field is one of the main oil and gas producing areas operated by VICO Indonesia in East Kalimantan, Indonesia. Production from this field has been focused mostly from shallow-level reservoir (C-I intervals). After production of more than 30 years, the shallow and high-permeability intervals are currently highly depleted. Meanwhile, deep and low-permeability reservoirs (J level) have rarely been penetrated leaving significant reserves. Accessing these reserves is a highly challenging work today. A recent well was drilled to access the reserves in a J sand but the drilling had to be stopped earlier due to total loss of circulation whilst penetrating a shallow high-permeability and highly depleted sandstone I082A.

An integrated pore pressure prediction approach has been carried out during the planning of drilling and completion of a proposed S86 well. The objective was to successfully access deep target reserves in the J sandstone by safely drilling through the highly-depleted I082A sandstone. The approach integrated available data including well logs, cores, formation pressure, historical-match derived pressures, and drilling parameters.

Pore pressure prediction showed that the proposed S86 well would penetrate normal pressure regime (8.45 ppg) to –8,500’ SS. Within this interval, variously depleted reservoirs (3–6 ppg) would be penetrated. Starting from –8,500’ SS to –10,680’ (TD), the well was predicted to enter overpressure environment (8.45–13 ppg). Within the environment, a higly depleted I082A with 500 psi (0.87 ppg) was estimated to be encountered at ~8,819’ SS. The pore pressure prediction study recommended 1) to drill with normal mudweight of 10–12 ppg and set 9–5/8" casing point before penetrating I082A sandstone, 2) to drill through I082A to its bottom with low mudweight (8–9 ppg) and isolate with 7" short liner, 3) drill 6" open-hole to TD with high mudweight (12–13 ppg). The newly proposed well safely drilled through the highly depleted I082A sandstone and access to the reserves in the targeted J sandstone was successfully achieved. This great success has opened up an opportunity for further development drilling in the Semberah field.
Innovative Water Shut Off Solution Combining Real Time Downhole Measurement and Analysis with Zonal Isolation Technologies for Horizontal Open Hole Producer in Ratawi Field - A Case History from Partitioned Zone
Authors: Utomo Bagio , Al-Harbi Mosad , Razzak Shehabuddin , Al-Hadyani Fahad S. , Hamid Saad , Shaheen Tarek , Noya Vidal , Boonjai Pimteera
Published: January 2012

The increasing water production in mature fields has a significant impact on production economics. A structured approach is required to tackle this challenge. Water shut-off (WSO) operations in open-hole horizontal wells do not carry a high success rate, however, careful candidate recognition and treatment can improve the chance of success. Ratawi is an Oolitic Limestone reservoir in Wafra oilfield, Partitioned Zone (PZ) between Saudi Arabia and Kuwait. The reservoir has been undergoing water-flooding for pressure maintenance since 1998. Majority of the wells are completed as open-hole horizontal producers on artificial lift.

The paper describes WSO performed in the biggest water producing well in Ratawi field with 94% water cut. Being located in the crestal area, where the preservation of reservoir energy has been a focus of the reservoir management strategy, made it a prime target for WSO which could lead to water flood optimization and improved sweep efficiency. The water shut-off treatment was designed with two-fold objective; primarily, to plug-off the fractures and the near wellbore area suspected to produce water and secondly, to isolate the open-hole to prevent the damage to the oil bearing zones.

The challenging conditions for WSO required a synergistic approach by combining the latest technologies to achieve the desired objective. Real-time downhole measurements from the Fiber Optic Assisted Coiled Tubing (FOACT) were combined with the Open-Hole Inflatable Bridge Plug (OHIBP) to improve operational reliability while reducing risks of failure. The real time measurements assisted in reliable single-run OHIBP inflation under sub-hydrostatic conditions and also played a vital role in fine tuning the gel concentration in real time based on the formation response.

Due to this holistic approach, 4000BWPD was eliminated and 30% oil gain was observed without any subsequent acidizing. Moreover, the additional cost of a replacement well and abandoning the existing well was saved. The success of this treatment opens the opportunity to apply the same technique to other potential candidates across the globe.
The Natural Fracture Evaluation in the Unconventional Tight Oligocene Reservoirs - Case Studies from CuuLong Basin, Southern Offshore Vietnam
Authors: Li Bingjian , Ngoc Nhi Nguyen Do , Nguyen Quan Quoc , Dong Hoang Ngoc , Duy Cao Le , Weichman Dave , Farag Sherif , Phuong Pham The
Published: January 2012

The Oligocene Formation in CuuLong Basin, Southern offshore Vietnam, is predominantly fluvial-lacustrine sand and shale sequences deposited above the pre-Tertiary granite basement. The reservoir sands are usually tight with average porosity about 10%, and variable but mostly low permeability. In many wells targeting the granite basement, significant oil shows have been detected when drilling through the Oligocene section. However, it is usually difficult to get a well to flow naturally from this section due to the tight matrix. Therefore, the Oligocene sands were rarely paid much attention.

With commercial discoveries of both oil and gas made in several fields in the CuuLong basin recently, reassessment of the potential for the Oligocene sands has been brought back to the agenda. Natural fractures or faults are among the most important aspects to evaluate when assessing this tight formation. This paper presents a few recent case studies on fracture characterization for the Oligocene reservoirs. The data used includes core, borehole images, conventional open-hole logs, mud logs as well as DST dynamic data. Natural fractures including both open and mineralized ones are quite common in the tight Oligocene formation even though the fracture density and type might vary from one well to another depending on the structural location of the well, proximity to faults and depth in the vertical sequence. It is believed that the naturally open fracture or fault plays an important role in enhancing the reservoir permeability for potential natural flow in a well. The healed fractures, on the other hand, might block the lateral reservoir communication. Locating the fractured zones is also important for perforation decision and frac job design, if stimulation is required for a well.
Fluids Re-Injection (FRI): A Waste Management Technique
Authors: Al-Duailej Yasser K. , Al-Khaldi Mohammed H. , Al-Yami Ibrahim S.
Published: January 2012

Disposal of produced fluids, during different well activities, has been one of the main challenges for field operators due to environmental and economical concerns. The limitations on the discharge of oily wastes in addition to other regional regulations have resulted in several efforts to develop technologies and techniques that can be utilized as on-site disposal mechanism. One technique is to re-inject produced fluids into non-productive permeable zones of adjacent wells.

A comprehensive lab investigation was conducted in order to explore the feasibility of re-injecting various produced fluids during different activities such as mudcake clean-out, completion, or well stimulation treatments. This study includes also a detailed investigation of emulsion and scaling potential of various produced fluids mixtures: oil/clean-out fluid, oil/spent acid, spent acid/formation brine and clean-out/formation brine. In addition, a series of coreflood experiments was conducted to assess the effect of produced fluids injection on the initial permeability of core plugs taken from non-productive sandstone formation. These experiments were conducted at reservoir temperature using representative cores and collected produced fluids.

Coreflooding experiments showed that the effect of oil injection on core plugs permeability was mainly constrained by the initial core permeability. In tight cores, K = 25 mD, injection of oil damaged the core by forming external oil filter cake on the face of core. However, in cores with high initial permeability, K > 1 D, nearly 10 PV of produced oil was injected with no observed formation damage. Similarly, clean-out fluids/oil mixtures were also injected with no observed formation damage. In contrast to oil/clean-out fluids, spent acid/oil injection effect on core permeability value was dependent on injected spent acid type. This paper provides the recommendations and limitations of using produced fluids re-injection as a waste management technique.
Experimental Design to Optimize Operating Conditions for SAGD Process, Peace River Oilsands, Alberta.
Authors: Nguyen Huy X. , Wisup Bae , Tran Xuan V. , Chung Taemoon
Published: January 2012

The SAGD process is a promising recovery method for producing heavy oils and bitumen resources. However, SAGD process has several economic risks including the high capital cost of initial investment for building ground facilities and uncertainties related to oil and gas prices. These risks may be critical in SAGD operation if the design for initial operating conditions is unsuitable. In order to ensure maximize profitability, optimal operation conditions should be evaluated by reservoir simulations.

In this study, central composite design and response surface methodology (RSM) were applied to determining optimal conditions for SAGD process. It was aimed to mitigate the risk of incomprehensive economic assessment on the process operation. The study started with the central composite face-centered (CCF) design to screen variables, and then insignificant variables were excluded from the study before developing the optimal design by response surface method. A two-stage approach was employed based on the efficient local optimization. At first, an initial sample of design was obtained using design of experiment technique. Simulation runs for design points were used to estimate oil recovery as well as NPV for each case. Based on the standard of CCF design, total 28 cases was run to optimize the parameters of operating conditions and the NPV responses during 10 years of simulation period. Second, RSM was used to search for promising designs in contour plots and response surface map. The best choice of operating conditions for maximizing the NPV correspond to well pattern spacing of 78m, steam rate of 640 m3/d, injector producer spacing of 14m, injection pressure of 6330 kPa, subcool 8°C, respectively.

Simulation results showed that cumulative oil for Fast-SAGD process does not significantly increase and even NPV is the lowest among the mentioned SAGD cases. In addition, cumulative oil recovery of SAGD1 base case is higher than those of SAGD2 and Fast-SAGD cases, as well as the lowest CSOR. However, in the economic point of view recognized that the case SAGD2 achieves the highest NPV, with the predicted values matched the experimental values reasonably well with R2 of 0.99 and Q2 of 0.88 for NPV response, while the NPV of Fast-SAGD process is the lowest because of the increasing capital cost for additional offset wells. Actually, the difference of 10kPa between steam injection pressure and reservoir pressure is not sufficient to increase the NPV for both Fast-SAGD and SAGD1 base case operations. The high cumulative oil is favorable conditions for accelerating profit, but oil and gas prices at that time is crucial to decide for operation conditions in heavy oil projects.
Challenges of Recovering by-Passed Condensate in Al-Raja Field Utilizing MBO Method
Authors: Gunawan Indra , Al-Abbasi Omar
Published: January 2012

This paper presents a case study on a reservoir simulation modeling of recycling gas condensate using Modified Black Oil formulation (MBO) to identify and recover the by-passed condensate in Al-Raja Field. Al-Raja field is a good candidate to utilize MBO formulation instead of fully compositional due to following reasons (1) Gas injection/recycling is able to maintain the reservoir pressure above or at the dew point pressure in Al-Raja Field. (2) by keeping reservoir pressure above dew point pressure, gas injection will prevent any Retrograde Liquid Deposit (RLD) occured in the reservoir. It was well accepted methodology that MBO can be used in lean to medium rich gas condensate reservoir under gas cycling above dew point.

Al-Raja field is located in the Eastern part of the Marib-AlJawf Basin Republic of Yemen. The field has a moderate-size medium rich gas condensate reservoir with an average gas production rate of 750 MMscf/D from 18 wells. The lean gas is being re-injected back into the reservoir using line-drive pattern wells. Some make up gas from nearby fields was provided to replace fuel and shrinkage volumes. The high vertical relief of the field structure leads to significant temperature gradient that resulted in challenges to model the oil-gas ratio (Rv). The primary objective of the study is (1) to evaluate the current gas recycling performance at well and field level, (2) identify the location of current by-passed condensate (3) utilize the model to improve and optimize the liquid recovery through several options of optimum field developments (infill wells).

To achieve the objectives, 3-D Static and Dynamic models with 4 components MBO definition were constructed. In this study, we will show how to generate PVT Modified Black Oil (MBO) properties such as solution gas-oil ratio (Rs), oil-gas ratio (Rv), oil formation volume factor (Bo), and gas formation factor (Bg), from PVT-EOS. Whitson and Torp procedures were selected to calculate MBO properties from PVT experimental data of gas condensate.

The use of the MBO approach enabled us to perform faster field performance history matching compared with the compositional. This approach preserves less run time to conduct the Al-Raja prediction including infill drilling optimization. The condensate-gas ratio distribution achieved after the history match process guided us to locate the optimum infill well locations in by-passed area for the future development. Moderate condensate areas were located, and several wells have been drilled and proved to be successful. More infill wells were recommended to raise the field production and recover the remaining reserve
A Novel Well Annular Barrier Solution Alternative to Swellable Casing Packers
Authors: Plessing Hans , Arnskov Michael Macdonald
Published: January 2012

Reservoirs with unstable formations or unable to sustain traditional cementing or other zonal isolation requirements may necessitate that additional external packers are incorporated. in the completion solution. Polymer-based packers are widely used in such cases as they are relatively uncomplicated to deploy, however, the degradeable polymers as such do also introduce an additional uncertainty and risk.

The approach presented is based on a solid metal expandable system developed for the applications where inflatable external casing packers traditionally have been used. The well annular barrier provides long term robust and reliable zonal isolation in cemented or un-cemented completions and may also be used in conjunction with liners or long-string casing. Additionally it provides higher differential pressure capacity and higher expansion coefficients without compromising the inner diameter. Consequently it does not impair or restrict flow conditions and furthermore enables subsequent well maintenance to take place unhindered.

The paper presents the development of a new solid metal expandable system for external casing applications and discusses the rationality behind the technology.
Crude Oil Recovery from Sludge Treated by Low IFT Micellar Emulsion
Authors: See Chun Hwa , Saphanuchart Wasan , Looi Ming Hoong , Loke Yoong Shang
Published: January 2012

Over time, crude oil in ship tankers will destabilize where heavier component of crude oil such as emulsified crude oil with sands, are partitioned at the bottom of storage tank. The presence of these components at the bottom of the storage tank such as water-in-oil emulsion, sands and insoluble heavy metals, will result in increase in density, viscosity and reduce in flowability. This thick and viscous mixture is called crude oil sludge. This part of the sludge normally tend to have high pour point (higher than ambient), up to 10 wt% of sands, water and heavy metals. The sludge is conventionally removed from the storage tank by using mechanical way in combination with high pressure hot water stream. The treated sludge from this process is normally highly viscous, >10,000 cP, and contain around 5-40 wt% of water. This sludge is a water-in-oil emulsion stabilized by the natural emulsifiers in original crude oil. Fine solid in the sludge is another factor to stabilize the water-in-oil emulsion by adsorbing at the oil/water interface. The high emulsion stabilization and high viscosity leads to difficulties in post-treatment to recover the oil, especially when the sludge has very high wax content.

This paper presents a case study of applying a biodegrable, low IFT (interfacial tension) micellar emulsion and solvent extraction for recovering oil from highly viscous crude oil sludge, which could not be recovered by the current processes. This process yields total hydrocarbon (liquid oil and wax) recovery higher than 80%. It could yield approximately 23% recovery of light oil from this sludge (equivalent to >80% extraction efficiency of light oil recovery calculated based on total light crude oil in the original sludge) while the current process does not recovery any light oil. The water stream can be recycled or easily treated. Sand that disposed was found to have less than 2% of hydrocarbons. Additinally, this process can be run at ambient temperature at around 25°C to30°C.
Development of and Validation of Small Volume Multi-Tasking Flow Assurance Tool
Authors: Burgass Rod , Tohidi Bahman
Published: January 2012

Wax and asphaltenes are well known to cause problems through adhesion and build-up on pipeline walls, restricting flow. Deployment of chemical inhibitors is commonly used in subsea pipelines. Measurement techniques for both asphaltenes and waxes commonly show widespread data scatter. Selection of inhibitor chemicals for both wax and asphaltenes are commonly based upon simple tests conducted on stabilised oil samples. This commonly leads to higher dose rates being used than actually required in the pipeline to successfully reduce or eliminate surface build-up.

We have developed a small volume testing facility for measuring wax and asphaltene phase equilibria and optimising inhibitor deployment. The developed device is based on Quartz Crystal Microbalance (QCM) Technology. The QCM is locally cooled to create a temperature gradient between bulk fluid and the surface of the QCM, simulating wall cooling effect. Different temperature gradients could be simulated. The developed device needs 35 ml of fluid and can work at high pressure conditions, simulating effect of pressure and dissolved gas on wax phase behaviour and adhesion tendencies. For wax evaluation, the device can closely simulate a typical "Cold Finger" test with many extra benefits, including; small size of the sample, being non-destructive, real time deposition rate, using live samples (as well as dead/stabilised samples).

In this communication we present some of the results generated using QCM Technology including Wax Appearance Temperatures (WAT) and Wax Disappearance Temperatures (WDT), wax inhibitor screening and results on asphaltene onset determination and inhibitor assessment. Results using the first prototype comparing with "Cold Finger" wax inhibitor screening and showing the effects of temperature gradient and pressure on wax build up for a live oil are presented. The results show that the device and technique proposed in this communication can provide a robust, reliable method for evaluating solid formation and deposition risks using very small sample volumes.
X-ray Micro-tomography Measurements of Fractured Tight Sandstone
Authors: Iglauer Stefan , Wang Shuo , Rasouli Vamegh
Published: January 2012

A tight sandstone was fractured in a triaxial stress cell by injecting fraccing fluid. The specimen was then scanned with a micro-computed tomograph. From the resulting three-dimensional images the fracture morphology and orientation could be determined. Such measurements can be supportive in the development and validation of fracture propagation models. Such models can help optimizing gas and/or oil production from shales, tight sands, carbonates and coal beds.
Application of Deep Hydraulic Jet Perforating to Enhance Oil Production in Thin Reservoir with Bottom Water
Authors: Xu Suxin , Luo Weiguo , Zeng Fanhua , Gu Yongan
Published: January 2012

Exploitation of thin oil reservoirs with bottom water is a difficult task. Oil production rates are decreased rapidly because of water coning and inapplicability of stimulation methods such as fracturing, in many instances which makes wells have to be suspended or abandoned even at low levels of recovery. In this paper, deep hydraulic jet perforating technique (DHJP) is presented which provides an effective way to exploit such kind of reservoirs. Also the strategy, equipments, and operational procedures of the deep hydraulic jet perforating are discussed.

Deep hydraulic jet perforating is different to the well-known hydrajet perforating (HJP). In the HJP, the typical penetration depths are 12.7–20.3 cm (Kritsanaphak, Tirichine & Abed, 2010) and the jet nozzle does not move during the process. For deep hydraulic jet perforating technique, the casing is windowed mechanically with high water-pressure and the formation is penetrated by the jetting, meanwhile, the nozzle driven by screw, keeps going further in the formation through the window. Thus, the extreme deep depth can be achieved to 2 m approximately depending on the formation characteristics, and stand-off of the tool inside the casing.

Compared with the most widely used conventional explosive shape-charge perforating, the advantages of deep hydraulic jet perforating include (1) creating superior connectivity between the wellbore and formation; (2) enlarging the oil contact area; (3) leaving less near-wellbore damage. Hence, deep hydraulic jet perforating can be a good alternative for well completion, formation damage removal and hydraulic fracturing.

Deep hydraulic jet perforating has been applied successfully in JS Oilfield for the thin formation with bottom water to enhance oil production. Totally 10 holes for two producers are penetrated in target zone and the effective hole depth ranges from 1.55 to 2.01 m. The production rates were doubled and the shut-in well is revitalized again.
Downhole Matched Solutions: Innovative Scientific Approach to More Efficient Assemblies
Authors: Barton Steven Paul , Baez Franklin , Gee Ryan
Published: January 2012

Selecting the correct motor and bit combination to drill specific formations is critical to efficiently attain the desired performance through a vertical, directional or lateral application. If the bit is too aggressive, it can stall the motor and significantly reduce the average rate of penetration (ROP). It will also increase the likelihood of premature failure of the elastomeric liner of the motor power section, or twist-off of internal components. If the bit is not aggressive enough, it will not make full use of the available motor power and the ROP will be sub-optimal.

A new generation of an intranet system matching tool has been developed, which enables the user to accurately match a drill bit to a specific motor design, in order to deliver a more reliable and greater degree of drilling efficiency. This new software tool incorporates an advanced logic regarding the configuration of the motor power section selected, and assesses this against the bit design based on the four fundamental bit performance indices: Aggressivity, Stability, Durability and Steerability. It also reviews key features of the bit, including length, gauge geometry, cutting structure and torque control component configuration.

This software comprises of an interface that uses an extensive database that contains logic tables which describe the multi-dimensional characteristics of the motor and the bit, combining two phases of the tool: first a selection of the ideal bit for an specific application, whether vertical, directional or lateral and secondly a matched configuration of the desired motor. The software also includes, a build-up rate predictor and interference fit guide.

A range of case studies have been compiled and clearly demonstrate the accuracy and versatility of this tool to allow improved drilling efficiency. This initiates the implementation of more advanced motor technologies.
Development of Experimental Techniques, Equipment and Thermodynamic Modelling for Investigating Systems with High CO2 Concentrations
Authors: Chapoy Antonin , Burgass Rod , Haghighi Hooman , Tohidi Bahman
Published: January 2012

In this communication we present experimental techniques, equipment and thermodynamic modelling for investigating systems with high CO2 concentrations, including gas reservoirs with high CO2 content and/or CO2-rich systems from capture processes. The experimental equipment consists of high pressure (1,000 bar) equilibrium cells operating over a wide temperature (-80 to 200 °C), GC, chilled mirror and Laser Hygrometer for water content measurements. A thermodynamic model based on Cubic-Plus-Association (CPA) equation of state has been used in modelling phase behaviour of CO2-rich systems. The hydrate-forming conditions are modelled by the solid solution theory of van der Waals and Platteeuw. The reliability of the thermodynamic model was evaluated using vapour – liquid equilibrium data.

CO2 is a partially polar compound present in many hydrocarbon reservoirs. Its concentration in some hydrocarbon reservoirs is very high, demanding accurate experimental data and thermodynamic modelling. Another important application is modelling phase behaviour and properties of CO2-rich systems from capture processes for transportation and storage.

The results show that the developed model, combined with a reliable database, is a powerful tool for modelling complex systems. The resulting thermodynamic model is able to conduct various calculations, including; gas solubilities in aqueous and non-aqueous phases, water content in CO2-rich systems, hydrate stability zone in the presence of methanol and/or glycols, dehydration requirements for preventing hydrate formation in gas or CO2-rich phase, and a large number of other calculations. The results of the predictions are compared with experimental data, demonstrating reliability of the techniques developed in this work.

CO2 coming from capture processes is generally not pure and can contain impurities such as water. In a typical gas sweetening unit, the acid gas stream will be saturated with water. The presence of water can result in ice and/or gas hydrate formation at low temperature conditions and cause blockage.
Optimizing Asset Lifecycle Maintenance Using A Streamlined RCM Method
Authors: Pangawijaya Eric
Published: January 2012

Description:

How often an asset fails and its associated cost depends on the quality of the maintenance program adopted by the asset owner. Most organizations use a CMMS (Computerized Maintenance Management System) best suited to the size of the project and assets to be maintained. In larger organizations, the choice of CMMS most often defaults to a standard package used across all their assets.

During the initial stages of a project lifecycle, the key functions for maintenance are often driven by the OEM in order to comply with the warranty clauses of their equipment. With time and better understanding of equipment behavior, the CMMS needs to be optimized to match the operators’ goals for their asset.

The control of maintenance functions is a complex problem. The time scales and functions vary, as does the complexity of decision-making. The complexity is caused by numerous output factors, such as safety, availability, reliability, quality and longevity. Each of these factors is in turn influenced by numerous input factors.
Ten Year Evolution and Field History of Design Changes for a Torque and Drag Reduction Performance Drilling Sub
Authors: McCormick John E. , Evans Chad D. , Kirkpatrick Cameron
Published: January 2012

The need for advances in the robustness and versatility of downhole tools is increasing as well geometries become more complex. With more challenging wells being drilled everyday even the most advanced tools need to be improved upon. This is typically where research and development (R&D) engineers play a vital role. They work closely with operations personnel to create and constantly improve downhole tools. As service companies typically are the R&D arm of the oilfield, tools and improved designs are primarily market driven. This paper will explore the development of a mechanical friction reduction tool (MFRT), which is sometimes necessary in ERD and complex geometry wells to overcome torque and drag limitations.

A tool starts as a concept that will overcome an obstacle when drilling or completing a well or ensure the safety and cost effectiveness of an operation. The R&D engineers take this idea and develop it into a first generation tool. They then meet with their managers, fellow engineers and operations managers to discuss the concept, the functionality, and the technical and financial viability of the tool. The engineers then go back and refine the design of the tool, after which is scheduled another design review meeting. This process undergoes several iterations, with more technical and managerial personnel involved each meeting, until a final design is agreed upon. This design review process is intended to manage the progress of the design, keeping check on the financial, functional, and implementation aspects of the tool.

Once the first articles have been manufactured and field trials run, these tools are run commercially. Close watch is kept on the use of the tools and any issue and need for improvement are addressed by the design team. Constant assessments of the tool’s performance are carried out. This paper describes the development of a tool over a ten year period using the MFRT as a case study. We look at specific changes made to the tool, why these changes were implemented, and field trial results for the different modifications.
Investigation of Indigenous Bacteria in Water-dissolved Natural Gas Fields for Preventing Microbial Clogging of Injection Wells
Authors: Wakizono Ryo , Sugai Yuichi , Sasaki Kyuro , Higuchi Yasunori , Muraoka Noriyuki
Published: January 2012

The brine that has been produced from water-dissolved natural gas reservoirs should be returned into reservoirs after the resources have been extracted to prevent the subsidence. However, the re-injectivity of the brine declines gradually; therefore, re-injection wells should be maintained by backwashing treatments. Colloidal materials like biofilms can be observed in solid materials that have been produced by the backwashing from the re-injection wells.

Because the brine contains not only dissolved natural gas but also high levels of iodine, the iodine is also extracted from the brine chemically using sulfuric acid and oxidizing agent; therefore, re-injected brine contains sulfate and dissolved oxygen abundantly. These chemicals may stimulate the metabolites of microorganisms that have influences on the clogging; therefore, we considered the influences of these materials on microorganisms that may cause the clogging in this study.

Column experiments were carried out using sand and brine that were collected in the gas field. The columns that the brine including indigenous microorganisms, dissolved oxygen and sulfate was injected into were clogged significantly. Iodide-oxidizing bacteria, iron-oxidizing bacteria and sulfate-reducing bacteria were found specifically in clogged columns, suggesting these microorganisms had influences on the clogging. In particular, Iodide-oxidizing bacteria were also found in original brine; therefore, it was assumed to have an important influence on the clogging.

Iodide-oxidizing bacteria convert iodide into iodine that corrodes iron in the sand under the presence of dissolved oxygen. Iron (II) ion that has been eluted from the sand is oxidized to iron (III) ion by iron-oxidizing bacteria under the presence of dissolved oxygen. Iron (III) ion forms ferric hydroxide colloid in the brine and it causes the clogging of the porous media.

From these mechanisms of the clogging, we can suggest removing dissolved oxygen as the most feasible countermeasures for the clogging.
Reservoir Characterisation of the Low Permeability Siliceous Barmer Hill Formation, Barmer Basin, India
Authors: Chowdhury M. , Singhal M. , Datta S. , Sunder V. , O’Sullivan T. , Hansen P. A. , Burley S. D.
Published: January 2012

The Barmer Hill Formation is a Palaeocene lacustrine deposit occurring in the Barmer Basin of northwestern India. The lake developed entirely within the rift basin and its sediments comprise a complex of shallow to deep water deposits. In much of the northern part of the basin, the upper part of the Barmer Hill Formation is characterised by the presence of a finely laminated siliceous unit. Millimeter scale laminations in this unit consist of highly siliceous lithofacies, interbedded with organic material and subordinate clay. This syn-rift unit varies from 50 to 250 meters in thickness and is known to be hydrocarbon-bearing through much of the basin from numerous well penetrations. It is characterised by high porosities (25-35%) but low permeabilities (0.1-4mD). Hydraulic fracturing well operations in this reservoir had produced stabilized oil flows in the range of 30-250 BOPD demonstrating commerciality.

Detailed reservoir characterisation of this siliceous Barmer Hill Formation unit has been carried out in advance of planned field development and further hydraulic fracturing activities. Outcrop samples and subsurface core data have been integrated to understand the unusual properties of the reservoir. Scanning Electron Microscope (SEM) examinations of subsurface core samples reveal microcrystalline quartz (chalcedony) as the main mineral present, whereas equivalent outcrop samples are dominated by both Opal-CT and chalcedony and contain opaline diatom tests. This integration of core and outcrop data indicates that the siliceous unit was likely formed through diagenetic alteration of biogenic silica from opal-A through opal-CT to microcrystalline quartz. Early oil migration may have helped to preserve the porosity in the subsurface resulting in high porosity-low permeability reservoir properties unusual for microcrystalline quartz.

Geomechanical properties were assessed from bulk rock X-ray diffraction (XRD) information and core data to identify the most suitable intervals for hydraulic fracture initiation. This XRD data has been used semi-quantitatively to predict reservoir brittleness using a ternary plot of quartz-carbonate-clay abundance whereas geomechanical properties viz. Poisson’s Ratio (PR), Young’s Modulus (YM) and Unconfined Compressive Strength (UCS) of each units are estimated from wireline density-sonic log data and calibrated with core plugs to quantify the fracability of the units. The in-situ stress orientation is estimated from image log interpretation to predict fracture propagation orientation and aid optimal well placement.

This integrated workflow combining geological, petrophysical and geomechanical properties for reservoir characterisation is being applied to support commercial development of the hydrocarbon resources of this low permeability siliceous unit.
Sustainable Development with First CDM Project In Thailand E&P
Authors: Getwech Chiratthakan , Pornsakulsakdi Lawan
Published: January 2012

PTTEP Siam Limited (PTTEPS), a subsidiary of PTT Exploration and Production Public Company Limited (PTTEP), has pioneered a Clean Development Mechanism (CDM) project that takes aim at recovering and then using associated gas from the oil wells of Thailand’s Sao Thian-A field. Situated in the S1 Concession area in Sukhothai Province, the Sao Thian-A field has produced approximately 1.5 MMscfd of associated gas and 1,900 BPD of crude oil. Without a CDM project, this associated gas, comprised primarily of methane with lesser amounts of other energy rich hydrocarbons, would have simply been continued to have been flared and more greenhouse gases would have been released into the atmosphere.

At its core, the CDM project involved the installation of a gas treatment system to filter out hydrocarbon droplets from the associated gas prior to its internal use and sale to external facility. The CDM Project has indeed helped the whole facility become more economically viable for further investment in similar such additional CDM units.

The CDM project was approved by the Designated National Authority of Thailand in December 2010. Key benefits of applying CDM to the overall Project included reduction of GHG emissions, which in turn, increased the global energy efficiency of the oil field; the reduction of non-renewable energy use; and the encouragement of best practice of associated oil management among oil and gas operators in Thailand. In addition to revenue gain from carbon emission reduction trading, this Project has fulfilled score-based criteria for national sustainable development evaluation: natural resources and environment, social, technology transfer and development, and economic growth.

This CDM application within a petroleum exploration and production project is Thailand’s first! If this Project receives final approval and is officially registered by the CDM Executive Board, it will no doubt encourage other operators in Thailand to initiate their own participation in this business.
History Matching and Permeability Increases of Mature Coalbed Methane Wells in San Juan Basin
Authors: Moore Robert L. , Loftin Debbie , Palmer Ian
Published: January 2012

We discuss detailed well history matches, from the San Juan basin, of coalbed methane (CBM) gas rates, water rates, and pressures. In the sweetspot (fairway) the matching includes permeability that increases strongly with depletion, and is assumed to be exponential, as indicated by independent well tests spaced over time. The permeability increases are well matched by the Palmer-Mansoori (P-M) model. We present statistics of permeability matching to field results by the P-M model in the fairway. First, initial cleat porosities are 0.05–0.17% and consistent with porosities derived from observed water rates. Large permeability increases are not consistent with large cleat porosities. Second, the permeability increase ratio, defined by the maximum permeability reached over the permeability at initial reservoir pressure, varies from 16–170. Third, the matrix shrinkage parameters agree with a recent lab measurement. Fourth, cleat-volume compressibility mostly increases with depletion, when matrix shrinkage becomes dominant and cleats open wider. Last, in many wells north-east of the fairway the perm increase with depletion was found to be similar to that seen in fairway wells. This again suggests cleat porosities less than roughly 0.3%.

At low reservoir pressures (<300 psi), we find that the exponential permeability increase flattens. This we have interpreted as coal failure due to stress changes instigated by matrix shrinkage. In fact the P-M model for stress changes can predict the onset of shear failure with depletion, which generally agrees with the timing of the flattening. This adds validity to the general applicability of the P-M model in CBM plays. The modeling is important in being able to better forecast gas rates and estimated ultimate recovery (EUR) for CBM wells, which can remain profitable for decades.
Best Practices and Lessons Learned in the Construction and Maintenance of a Complex Gas Asset Integrated Production Model (IPM)
Authors: Amudo C. , Walters M. S. , O'Reilly D. I. , Clough M. D. , Beinke J. P. , Sawiris R. S.
Published: January 2012

Petroleum Experts’ Integrated Production Model (IPM) suite of software is widely used in the E&P industry especially for project evaluations that require integration of both surface and subsurface models. There is evidence in the literature to show diverse applications in field development planning, integrated forecasting, surveillance and production system optimization. Perhaps less reported are the lessons learned and best practices in using the IPM software. This paper focuses on these issues using Chevron’s IPM model for some of its largest gas fields.

The Non-Operated Joint Venture (NOJV) Subsurface Team began developing an IPM model for one of its biggest gas assets in 2005. With explicit modeling of critical components like compressors, dozens of wells and reservoir tanks, platforms, fluid characterisation, gas-water contact movement, pipelines, sub-sea manifolds and separators, this is arguably the largest and most complex IPM model in Chevron. The model continues to play a critical role in Chevron’s effective capital stewardship of the gas asset. The need to maintain the credibility of this model cannot be over-emphasized, and the model has undergone several phases of enhancement to ensure that it continues to meet business objectives.

This paper describes some of the best practices and lessons learned in constructing and maintaining a complex IPM model. It is intended as a resource for IPM practitioners. Examples cover all aspects of the IPM from the non-technical (e.g. framing the problem, case definition and naming convention) to the technical (e.g. model construction, model maintenance, software limitations, constraint violations, production optimisation and quality assurance checks).
The Successful Planning and Implementation of High Angle Deviated HPHT Well Testing in the Sour Naturally Fractured Gas Reservoir: Case Study of S-3 Well
Authors: Akbar Dino , Simanjuntak Timur M , Kristianawatie Nova
Published: January 2012

In the oil and gas industry, reservoir pressures exceeding 10,000 psi and temperatures exceeding 300°F are categorized as high pressure and high temperature (HPHT) reservoirs1. Testing and design for HPHT wells require special equipment and treatment, including the use of technology that can withstand high pressure, high temperature, H2S and high CO2 content.

S-3 gas well is a high deviated (inclination: 88°) well with open-hole completion. Pressure and temperature of S-3 well are estimated at 10,625 psi and 408°F respectively. Based on gas chromatograph analysis, the H2S content is around 100 – 250 ppm and CO2 content around 30%.

Due to low matrix permeability indication around S-3 (<5md), a Modified Isochronal Test (MIT) test was chosen for S-3 to shorten testing times. Pressure, rate and temperature were measured using surface recording equipment due to the availability of tools that meet pressure and temperature rating. Static reservoir pressure was predicted using Cullender and Smith method. Nodal analysis software and WHP vs BHP relationship from S-1 well is used to calculate IPR and Deliverability curve. Permeability and skin factor was estimated from drawdown analysis.

This paper presents the history and a case study of S-3 well testing, including planning, testing design, execution, data analysis, interpretation, and lessons learned from the well. This will be beneficial for designing the next well-testing and optimizing similar HPHT wells.

Finally, as a result of S-3 well testing, it was found that AOF from pseudo pressure function was around 155 MMscfd, kh 3315 md.ft, while the total number of skins was 29. There is also an indication of fracture occurrences around S-3.
Six Sigma Approach to meet Gas Dehydration Unit Optimization
Authors: Al-Adwani Adnan E. , Al-Zuwayer Hamad , Kapavarapu Venkata Madhusudana
Published: January 2012

KOC is having Booster stations facilities to compress the gas from LP and HP pressures to Very High Pressure and transport to KNPC plant for heavier extraction. BS-140 and BS-150 facilities are designed to dehydrate wet gas to 20.90 Lb. /MMSCF and 21.90 Lb. /MMSCF as part of COSTAIN improvements in 1999. BS-140 & 150 facilities are struggling with high glycol consumption and leading to higher operating costs for KOC. In order to provide solutions for the long standing issues like higher Glycol consumption and causing indirect impact on Operating cost of the Process facilities, Six Sigma approach selected for optimizing the Gas Dehydration unit performance in BS-140 facilities.

Team conducted detailed analysis and various process reviews carried out and BS-140 TR-II selected as role model for implementing the operational parameters modifications and monitored the summer period Glycol consumption. Team selected Six Sigma process plan to achieve good results. As part of Six Sigma approach, MAIC (Measure, Analyze, Improve and control) action plan implemented to meet the objectives.

After the improvements resulted 33% glycol consumption reduction (Revenue of US$ 565,049 Approx.)In normal operating scenarios without any business process operations interruption by implementing minor operational improvements.
Ensuring Well Integrity in Deepwater using a fit for Purpose Advanced Cement System
Authors: Taoutaou Salim , Azwar Cinto , Pathak Rakesh , Nzoutchoua Nana Degaul , Ajwani Prakash
Published: January 2012

Deepwater is one of the most technically and logistically challenging environments for cementing operations because of the risks associated with the conductor and surface casing cementing. Understanding the technical challenges, and mitigating the geological risks such as low temperature at seabed and fracture gradient, as well as shallow flow hazards including shallow water flow and gas Hydrates are key to designing cement slurries that can meet deepwater specifications and provide required zonal isolation.

This paper will discuss the real challenges faced during the cementation of critical surface casing for a major operator in India. The maximum operating water depth was 2,965 m [9037.3 ft]. Shallow gas flow, was encountered during the drilling of top hole sections. A low seabed temperature of 2 ºC [35.6 ºF] was also encountered in all the wells, and the narrow margin between the pore pressure and fracture gradient necessitated the requirement of lightweight cement slurry of 1378 kg/m3 [11.5ppg].

All of these challenges were resolved by using an innovative cement system based on Optimized Particle Size Distribution (OPSD), combined with a proprietary low temperature gas migration control additive, used for the first time in India.

The zonal isolation was achieved using the OPSD system and a proper gas migration control additive system.