bluuebunny/crossref_metadata_2025 huggingface dataset:
A Three-Phase Non-Darcy Flow Formulation in Reservoir Simulation
Authors: Su HoJeen
Published: December 2007

Non-Darcy flow correction is necessary in matching gas well deliverability test data as documented in the literature. There were also several research reports discussing the non-Darcy flow behavior observed in oil flow cases. However, the non-Darcy flow data from oil wells have not been rigorously analyzed in the past.

This work extends the Forchheimer formulation for a three-phase system. We derived an equation to relate the non-Darcy flow coefficient of the cell-to-cell flow term in the reservoir mass balance equations to the rate-dependent skin coefficient in the well equation. This development is applicable to a 3-Phase system and allowed us to obtain the non-Darcy flow coefficient values from oil flow tests. Those values from oil well data were far greater than the values predicted by correlations derived from gas flow test data.

Reservoir simulators used a so-called non-Darcy flow resistance factor to account for the non-Darcy flow effect in calculating flux terms. We derived a simple expression for the derivatives of the non-Darcy flow resistance factor. This would facilitate the implementation of the fully implicit formulation in modeling non-Darcy flow problems.

For gas flows, if there was an excessive pressure drop from well-block cell center to well bore, the well equation would over-predict well deliverability. A new and simple correction factor was derived to improve gas flow prediction.

Reservoir simulation runs were made using this new formulation to match field test data from both gas and oil wells.
Analysis of Interference Testing of Horizontal Wells in an Anisotropic Medium
Authors: Houali Achour , Tiab Djebbar
Published: December 2007

Interference tests provide valuable information about reservoir characteristics such as aerial average transmissibility, storativity, and degree of communication between wells. Due to the larger radius of influence and larger contact area of a horizontal well with the formation than its vertical counterpart, the transmissibility and storativity obtained from interference testing of horizontal wells would be more representative of the formation characteristics than those obtained from interference testing of vertical wells.

Very few studies have been made about interference testing of horizontal well. Malekzadeh and Tiab1 were the first to analyze and give solution for interference test of horizontal wells. They presented type curves with corresponding equations for the analysis; they also presented a direct method to analyze these tests. Their work however is limited to the study of an isotropic medium. To date, a solution to the problem of interference testing of horizontal wells in an anisotropic medium and the corresponding type curves have not been presented.

In this study, a method, based on the pressure derivative function, is presented for analyzing the interference testing of horizontal wells in an anisotropic medium. Type curves of dimensionless pressure and dimensionless pressure derivative have been presented, with the corresponding equations to calculate the directional permeability and the storativity. It has been found that type curves presented in this study for the case of an isotropic medium match well those obtained by Malekzadeh and Tiab under the same conditions.

A direct method using pressure derivative curve, based on the Tiab's Direct Synthesis (TDS) technique, is also presented to calculate the permeability in both directions and the storativity. The model was validated by matching the numerical and the analytical curves of pressure and pressure derivative. A sensitivity analysis was performed to investigate the effect of the following parameters on the proposed technique: permeability anisotropy, distance between the interfering wells, and the length of the horizontal drains. It has been concluded that the horizontal permeability anisotropy and the distance between the interfering wells have a significant effect on the behavior of the pressure and pressure derivative, whereas the length of the horizontal drain only slightly affects these responses.
An Improved Correlation to Estimate Productivity Index in Horizontal Wells
Authors: Escobar Freddy H. , Saavedra Nestor F. , Aranda Robin F. , Herrera John F.
Published: December 2007

Proposal

Because their great efficiency in producing higher flow rates per unit pressure drawdown, horizontal wells have currently become a popular alternative for the development of hydrocarbon fields around the world. So far, most of the introduced correlations to estimate the productivity index for these wells have shown certain differences among their results. This does not allow us to properly establish which one of them provides the closest value to the actual one, since there is no evidence of a trustable enough reference point.

Throughout the years, several investigations for the determination of horizontal-well productivity index have been carried out. These researches have been focused on the determination of steady-state solutions for the above-mentioned parameter, therefore, a diverse number of correlations have been introduced. These correlations have been presented by such very well-known researchers as Giger, Borisov3, Merkulov2, Renard & Dupuy2–5 and Joshi2–5. They are mainly based upon complex analytic solutions which may have some uncertainties when applying them.

This paper proposes an improved steady-state correlation to calculate productivity index for horizontal wells and evaluates the most commonly used existing correlations to estimate this parameter by using numerical simulation. Besides that, a sensitivity analysis on the influence of the variation of each variable in the existing and proposed models was carried out. The analysis was conducted by generating a synthetic drawdown test by means of a commercial reservoir simulator. Using the pressure derivative curve, a time range where steady-state behavior takes place was defined. Then, a simulation was performed with the purpose of determining the pressure distribution in the reservoir within that range of time. This allows us to estimate the horizontal-well productivity index for any drainage radius.

More than 500 simulation runs were performed to estimate the results obtained by the improved correlation introduced in this work and the existing ones. Several plots of productivity index versus each one of the model variables were constructed for comparison purposes. It was observed that Joshi's correlation matches well with the simulated results. However, the proposed correlation provides much better results than those provided by Joshi's within a very wide range of variation of the parameters involved in the different correlations.
Development of Low Risk, High Level TAML Level 5 Multilaterals in the South China Sea
Authors: Park Jonathan , Shen Duo Wei , Yong Li Wen , Cun Yuan Fu
Published: December 2007

The ConocoPhillips Xijiang field in the South China Sea requires multilaterals to increase oil production from a limited number of available platform slots. Further development in this area depends heavily on slot recovery to maximize production and minimize hole collisions caused by frequent sidetracking in cluster wells.

This paper discusses a novel method used to install low-risk multilaterals on these wells. This method reduced the risk and time associated with TAML (Technology Advancement of Multilaterals) Level 5 multilateral completions. By definition, a TAML Level 5 multilateral provides hydraulic isolation at the junction by using straddle tubular run as part of the final completion. In the past, constructing Level 5 junctions required the lateral liner to be cemented and later washed over in order to remove the portion of lateral liner left in the mainbore. This complex and time consuming process created additional debris, which had to be managed, along with potentially unstable junctions. The method discussed in this paper eliminates the need for this risky washover operation, resulting in lower risk and less installation time.

This new Level 5 multilateral installation method is based on proven tools and techniques currently used to create Level 3 multilaterals. This further reduces the potential risk and specialized equipment requirements of the multilateral system. This new type of Level 5 multilateral was designed to allow for maximum flexibility of the final completion assembly. The completion design provides for control of the laterals via slickline by making the Level 5 system compatible with the 2 7/8-in. bypass tubing around an electrical submersible pump.
Gas Field Monetisation: Major Investment Drivers for Gas-to-Power Ventures
Authors: Osaghae Ephraim O. , Khan Javeed A. , Rao Voola Jo. J.
Published: December 2007

Vertical integration between natural gas and power generating companies is essential in ensuring profitable monetisation of the massive natural gas fields in all regions of the world, including the Asia-Pacific. With a simple economic model, major investment drivers most likely to ensure the success of such integration have been highlighted in this study.

The sub-surface and surface engineering data inputs into this model were obtained from a natural gas company conducting a test trial of feeding gas into a 14.4-24 MW Power Plant. Data included production profiles, facility costs and historical performance obtained from both gas and power sides of the integrated venture. Also included in the modelling were prevailing regimes of fiscal and government incentives. Adequate measures of economic and risk analyses were implemented. To validate the model, the assumptions were passed through challenge sessions, and many runs of other investment options were made. The outputs were checked for consistency.

The results have shown that gas-to-power profitability, and hence final investment decisions, are mostly affected by changes in gas and power market prices. Supply reliability, government interventions, project location, and expected return are the next set of important variables any investor should closely monitor. Natural gas costs and electricity consumption pattern additionally affect the power generation side of the venture. Effectively identifying, evaluating, and communicating these investment drivers should ensure profitable gas field monetisation - in the form of gas-to-power ventures. Project optimisation and effective business control should also be facilitated.
Forecast of Natural Gas Development: from the Point of Reserve-production Ratio
Authors: Feng-Jiang Wang , Xin-Hua Ma , Lian-Zhu Cong
Published: December 2007

Reserve-production ratio (RPR) is a key factor in the strategy of natural gas development. According to the characteristics in the course of gas industry development, a four-stage mode was developed. Current stage for China's gas development was identified as a benchmark for prediction. The factors influencing RPR were analyzed, and the rational RPR level for China was discussed. The gas development of China was predicted using a method taking RPR as a controlling factor.
An Illustration of the Information that can be Obtained from Pressure Transient Analysis of Wireline Formation Test Data
Authors: Daungkaew S. , Prosser D. J. , Manescu A. , Morales M.
Published: December 2007

The theoretical analysis of pressure response associated with Wireline Formation Test (WFT) data was first introduced in 1962 by Moran and Finklea1 but was generally not widely used due to its radius of investigation being very small comparable to that of conventional drill stem testing, and due to gauge resolution limit2. Analytical techniques using pressure derivative curves introduced by Bourdet et. al. (1983)3 have subsequently had a significant impact on the increased use of pressure transient analysis (PTA) techniques. This paper aims to illustrate the wide range of information that can be obtained from WFT data using an advanced well test analysis technique to analyze the WFT pressure response, and is illustrated using field examples from the Asia Pacific Region. A single well model numerical simulation for a wireline formation tester deploying a single probe is used to verify the PTA results presented. An analytical solution in well test analysis software is also used to generate pressure transient response to confirm results from actual field examples.
Design and Qualification of a Remotely-Operated, Downhole Flow Control System for High-Rate Water Injection in Deepwater
Authors: Bussear Terry , Barrilleaux Mark
Published: December 2007

Consistent with the concerns of many deepwater developments being contemplated throughout the world, this paper reviews the challenges, methodologies and detailed conclusions associated with the implementation of selective water injection for pressure support in ultra-deepwater, subsea developments operated by BP. The potential benefits associated with remote control of selective water injection in any of 2 - 6 zones within a single well, include reducing well count, reducing interventions and increasing recovery.

This paper focuses on the operational requirements and considerations associated with the development of soundly engineered intelligent well systems, capable of a 15-year design life, with sustained injection of 45,000 BWPD per well, into any remotely selected zone. Principal areas of discussion include: mitigation of potential erosion at these rates through 3-1/2" tubing flow control valves within 7" liner completions; inter-zonal isolation competency with differential pressures up to 7,500 psi; and downhole hydraulic systems design for remote-control at hydrostatic pressures of 18,000 psi and differential pressures up to 12,000 psi.

In addition to the downhole extremes in flow rates and pressures, we discuss the considerations within the subsea control systems of these wells; the assessment of various downhole hydraulic control architectures; and the effects of the operating temperature extremes.

The principles, processes and "lessons learned" in design of this system can serve as a benchmark for other high-value, deepwater, subsea injection applications in which the reservoir barrier conditions are not well understood, and hence considered candidates for intelligent well systems.
Kikeh ESS Well Test - A Case History of a Deepwater Well Test, Offshore Malaysia
Authors: Hampshire Kenneth C , Stokes Dan , Omar Norjusni F , Tomkins Patrick G
Published: December 2007

It has been demonstrated that Expandable Sand Screen (ESS) technologies can be implemented rapidly and effectively without the requirement of a dedicated completion brine and well clean-up.

This paper will discuss a case history of the Kikeh #4 deepwater well test, performed in Block K, offshore Sabah, Malaysia. The test was performed in 4500 WD, from Diamond Offshore's fifth generation semi-submersible rig, "Ocean Rover".

Due to poor flow performance on the initial frac-packed completion, the decision was made to fast track this non-conventional approach to deepwater well test design. Key topics of discussion include: an integrated oil-based drill-in and completion fluid, expandable sand screen (ESS) selection, well test objectives, and well performance. Other points of discussion will include recommended practices and lessons learned using this completion technique. The completion and well test exceeded the objectives at a reduced cost and lower risk than conventional completion methods. As a result of the success of this methodology, it will be adopted for subsequent well tests in the area and is currently under consideration as the mainstay completion technique for the Kikeh development program.
Subsea Leaks Cured with Pressure-Activated Sealant
Authors: Rusch David W.
Published: December 2007

The paper describes the use of a pressure activated sealant technology to cure leaks in subsea wellbore equipment and control systems. The benefit of this technology is that use of an injectable pressure activated sealant to cure leaks provides a safe, cost-effective alternative to conventional well interventions. The paper outlines the capabilities of the pressure-activated sealants, the procedures used and the results of the sealant operations including case histories.
Building the Case for Raw Seawater Injection Scheme in Barton
Authors: Flatval Kirsti Berg , Sathyamoorthy Sekhar , Kuijvenhoven Cor , Ligthelm Dick
Published: December 2007

Shell Malaysia Exploration & Production (SM-EP) is planning for secondary recovery via water injection in the Barton field by using the novel concept of raw seawater injection. Raw seawater injection is essentially injection of minimally treated, fully aerated seawater. The seawater having undergone limited solids interception only by coarse filtration. The concept of raw seawater injection has not received much interest from operators due to lack of understanding on issues such as reservoir souring and impact of oxygen on the reservoir. However, raw seawater injection has proven to be the most cost effective secondary recovery design for mature fields like Barton, which do not boast huge reserves. This paper will focus on work carried out to identify and mitigate additional risks from raw seawater injection, principally on issues of reservoir souring, increased corrosion on production system, increased levels of suspended solids and impact of oxygen on the reservoir scale. Raw seawater injection in Barton will be the first of its type in the Shell Group and only the second known attempt in the industry.
Vessel-Less S3: Advanced Solution to Slugging Pipelines
Authors: Kovalev K. , Seelen M. G. W. M. , Haandrikman G.
Published: December 2007

In a flowline/riser system large liquid slugs and gas surges can be formed by operational changes or can be due to the specific flow conditions and physical characteristics of the flowline. These liquid slugs and gas surges may result into significant oil and gas production deferment. Slugging may cause high-level trips in separators and can lead to unstable operation of topside facilities.

Slug mitigation plays a very important role in the drive of exploration and production companies for operational excellence and increased profits. Shell Global Solutions is developing cutting-edge technologies to solve problems associated with slugging. In the late nineties Shell Global Solutions developed the Slug Suppression System (S3) that is now in operation in the North Sea. The field experience with the system has proven that the S3 controls/mitigates slugging.

Striving for advanced technical and cost-efficient solutions, we have developed a new slug suppression device: the Vessel-Less S3. The new product integrates the benefits of the conventional S3 controller schemes and the T-junction in-line separation technology as an efficient means of slug mitigation. The new system comprises a stratifier, a downcomer, two T-junctions, gas and liquid outlets and two control valves. The control algorithms of the original S3 are applied for the slug mitigation and control. Instead of the vessel, standard piping is used in the construction of the Vessel-Less S3.

On the way to a new commercial product, the Vessel-Less S3 has now been proven in laboratory environment, and needs to be tested further in the field. The Vessel-Less S3 has the potential to become an attractive device for slug mitigation and control. The development of the Vessel-Less S3 will enable operating companies to implement the S3 technology at lower costs and with reduced weight/space requirements.
Managing Subsidence Risk in Gas Carbonate Fields Offshore Sarawak
Authors: Mah Kok-Gin , Draup Awang
Published: December 2007

The porous carbonate formations in the Central Luconia Province offshore Sarawak generally form prolific gas producing reservoirs. As more and more gas is being produced from those high-porosity mouldic limestone reservoirs, the platform structures at surface gradually "sink" deeper into the seabed of the South China Sea. Although the exact magnitude of this subsidence is always not simple to predict, the general effect is catered for in the various technical designs of the platform complexes.

Asset and well integrity of these fields are crucial to ensure security of gas supply. An intensive surveillance programme is in place to ensure all relevant data are obtained to assess asset integrity risks. Dedicated studies and modeling are also being carried out to provide improved subsurface understanding of sudsidence behavior, as well as to evaluate structural integrity. No field is currently subject to integrity threat associated with compaction and subsidence. By formulating early mitigation plans, we are able to ensure safe operations of all the fields. The particular merit of this paper is to share some of the lessons learnt from field case histories and the surveillance approach and mitigating measures taken to manage the risks.
Stybarrow Oil Field - From Seismic to Production, The Integrated Story So Far
Authors: Ementon Neil , Hill Robin , Flynn Mark , Motta Bob , Sinclair Steve
Published: December 2007

The Stybarrow Oil Field is located in Block WA-255-P offshore Western Australia, in an average water depth of 800m. This paper is a work-in-progress case-study of the process of discovery and appraisal of the Stybarrow field, and the influence on appraisal and development decisions of integrating the various types of geological, geophysical, and engineering data and techniques available to the modern oil company and their partners.

In the fault bounded Stybarrow structure, medium viscosity, medium GOR oil is reservoired in high quality but friable sandstones of the Lower Cretaceous Macedon Member. The average reservoir depth is around 2200mSS. High quality 3D seismic data has been used to both significantly reduce uncertainty in modelling the Stybarrow structure, and attempt to predict reservoir quality and distribution using well-calibrated seismic inversion to relative acoustic impedance. Results from the use of seismic inversion have been fundamental in constructing static reservoir models. The static geological modelling has been used in the construction of simulation models, with the view to simulating flow of the near-saturated oil through the relatively thin Macedon reservoir and thus predicting production. Pre-project feasibility simulation results were used to select a preferred reservoir management scheme. A simulation derived Integrated Production Model was then constructed. This allowed examination of the interaction of reservoir with a proposed processing and facilities under given processing facility design constraints.

The influence of a number of data types on appraisal decision making and development planning is discussed. Elaboration is also made on the impact of near-field exploration potential, and the possible influence of this potential on Stybarrow development planning is also discussed.
Rapid Derivation of in-place Hydrocarbon Volumes in Large, Complex Field Settings
Authors: Holyoak Steve
Published: December 2007

Proposal

South West Ampa Field in Brunei is a large, structurally complex oil and gas field offshore Belait, Brunei Darussalam. Starting with seismic interpretation in the time domain, this paper describes a modeling workflow culminating in the derivation of initial in-place volumes for oil, associated gas, and non-associated gas. At the centre of the process is an integrated full-field reservoir model. The initial phases of the workflow are summarised only; these are described in more detail in Reference 1. In this paper emphasis is placed on the derivation of the hydrocarbon volumes, and is based on work carried out over the last year.

Deriving volumetrics from an integrated full-field reservoir model has several advantages over more traditional methodologies: Graphically auditableForced consistency with the live reservoir modelRapidly re-run through pre-existing user-defined workflowsOutput format facilitates further analysis using spreadsheets or relational databases

This paper also discusses areas for possible improvement: The method is more susceptible to gridding artifactsCurrently the volumes are largely deterministic in nature; probabilistic modeling is feasible, but at the detailed reservoir level is likely to require a much more hands-on approachAdditional software enhancements are required to further streamline the process

To date the emphasis has been on designing a suitable workflow. This has now been achieved, and the study will move forward to a phase of comparison with the existing corporate volumetrics database. This may generate additional opportunities for infill drilling.

There are many additional benefits of the full-field model.

These include: Rapid output of maps and cross-sections for reports and well proposalsWell planning in a collaborative three-dimensional environmentEase of integration of diverse datasets (for example well paths, seismic data, formation tops)Live model updating with results of ongoing activitiesThe ability to use the full field model as the basis of detailed models for dynamic simulation

The model is already playing an important role in the drive to maximise hydrocarbon recovery from this large but highly mature field.
Experimental Design Methodology for Quantifying UR Distribution Curve - Lessons Learnt and Still to be Learnt
Authors: Peng Cheong Yaw , Gupta Ritu , Vijayan Kaipillil , Smith Gregory C. , Rayfield Mark A. , DePledge David R.
Published: December 2007

Experimental design and analysis (EDA) methods have been proved to have a great potential in multiple deterministic and stochastic approaches to quantify the ultimate recovery uncertainty of a subsurface reservoir. Nevertheless, it is still at the very beginning stage, and is important to improve the performance and the efficiency of the methods in such oil/gas applications. This paper provides some lessons learnt in such studies, and propose the lessons still to be learnt.

A brief summary of the EDA methods that are applied in ultimate recovery uncertainty studies is presented, and this paper emphasised on the importance of expert knowledge in improving the efficiency of the EDA methodology in such oil/gas applications, where the number of settings of the uncertainties is small and only a small number of models can be simulated. Response surface method in conjunction with the design matrix guided by expert knowledge turns out to be the best approach to develop a surrogate model (simple mathematical function) of ultimate recovery based on uncertainties. Once the model is fitted it is important to quantify the accuracy of the surrogate model. This surrogate model can be put to multiple use like prediction, optimisation etc.
Operational Experience of Wet Gas Metering in Malaysia
Authors: de Leeuw H. , Dybdahl B. , Nilsson C. N. , Kamal Mustaffa
Published: December 2007

Wet gas metering technology was chosen by ExxonMobil for continuous well testing and advanced production measurement at two satellite platforms located in the South China Sea offshore Malaysia. The satellite facilities are equipped with permanently installed SmartVent wet gas venturi based meters at each well location. Special wet gas flow calculation and monitoring software have been developed and installed on a separate flow computer installation interfaced to the host platform DCS system.

Prior to installation the wet gas meters have been subjected to full scale testing at a representative high pressure gas/liquid flow test facility. This has resulted in valuable measurement experience and a unique set of experimental wet gas data. After start up of the field on-site verification/calibration will be performed using the tracer technology method. As of today valuable results have been obtained from the system.

The present application is a demonstration that wet gas flow measurement is increasingly gaining acceptance in replacing expensive well test separators and related infrastructure in gas/condensate field developments. Besides the significant cost savings, the availability of continuous readings of each well's production rates allows for enhanced reservoir management and production optimisation. At the same time experience has shown that successful implementation of wet gas flow measurement requires adequate attention to every aspect of the metering process.
Challenges to Improve Turbomachinery Availability
Authors: Hasnan Nasir , Nazim Saiful , Yusof Yuzaini
Published: December 2007

This paper presents challenges and initiatives to improve turbomachinery availability to maximize production. Since 1996 it had gradually increased from 85% to 96% in 2003. Various initiatives were implemented and ongoing to make the improvement. However, year 2004 turn out to be an extremely challenging year with plenty of unplan downtime due to something that was never anticipated.
Control Medium Selection for Unmanned Wellhead Platforms
Authors: Morgan Julie , Shipchandler Arif , Mukhopadhyay Santanu
Published: December 2007

Cost effective design of unmanned wellhead platforms require highly reliable, low maintenance equipment/systems which minimize production downtime and reduce the frequency of site visits. In the Asia Pacific region, in line with this philosophy untreated wellhead gas is commonly used in lieu of instrument air. However the quality of this gas is poorer than instrument air which could reduce the control system reliability and accelerate wear and tear of control components. Granherne Inc has developed an innovative treatment scheme which produces wellhead (instrument) gas comparable in quality to instrument air using reliable, inexpensive and low maintenance equipment. This paper describes this scheme and identifies its potential benefits over an alternative control medium such as a hydraulic fluid.
A New Approach for Regime Optimization of Oil and Gas Mixture Pipeline Transportation
Authors: Khang Nguyen Thuc , van Bich Ha , Son Tong Canh , Hoe Le Dinh , Thuc Phung Dinh
Published: December 2007

The performance of pipeline transportation of oil & gas mixtures can be optimized by different ways. This paper introduces a synergetic statistical approach based on field data to analyzing the oscillations of pressure by determining simultaneously Hausdorff's Dimension "D", Hurst's Index "H" and the Entropies "E", as a useful tool for managing the multiphase pipeline transportation systems.
Inhibitor Squeeze Design and Returns Monitoring to Manage Downhole Scale Problem
Authors: Darwish Sameh F. , Moniem Alaa A.
Published: December 2007

Proposal

Downhole scale deposition in producing well bores is becoming a serious problem to most of oil companies, especially when dealing with deep wells. The problem will be greater for those companies that are using water flood to maintain the reservoir pressure as the scale is often Calcium, Barium, and Strontium Sulphates.

The options for the scale removal varies from chemical, mechanical removals and at the worst conditions full rig work over to replace the production tubing could be the only available option. The oil field scale treatment philosophy is "scale prevention is better than curing", accordingly, implementing inhibition programs is generally become the most efficient scale treatment technology. However this inhibition technology is based on many factors to enable an appropriate assessment and reliable conclusions: How the inhibitor interact with the formation rock matrix.Thermal stability of inhibitor.Deployment and return profile.

In this paper, a sever downhole scale problem occurred at Ras Budran field that located at the eastern coast of Gulf of Suez in Red Sea territory, were presented and focused on: The treatment parameters starting from the traditional chemical & mechanical removal techniques and finalizing by the squeeze inhibition programs.Inhibition programs and its modification to overcome the formation problems.Inhibitor deployment, fluid returns monitoring and optimization.Inhibition lifetimes pronounced improvement for all the scaling wells.Study different chemistry of scale inhibitors to improve adsorption/desorption profile.
KLX/KLY Reservoir Management Using Integrated Asset Modeling, Case Study
Authors: Tjahyadi Riza , Suyasa I Made
Published: December 2007

One of the most important areas in Offshore North West Java is KLX/KLY fields, considering their high contribution to the West Java total gas production. Four platforms have been developed in this field to produce gas from shallow, thick and low strength carbonate reservoir. The large gas accumulation in this field is within a thick carbonate build up formation with average gas column thickness of 350-400 ft underlain by the aquifer. The reservoir has high porosities ranging from 32 to 45% and high permeabilities up to several Darcies. As consequences of dominating gas production, reservoir pressure has dropped and gas production rate decreased in this area. To ensure production continuation, well problem anticipation and surface facility remediation, Integrated Asset Modeling (IAM) have been built. Currently, this Asset is focusing on three important sectors, which are Low Pressure Compression, Well Surveillances Planning and Subsidence Management. Low Pressure Compressor ProjectSome scenarios for Low Pressure Compressor Project had been created to optimize gas production and maximize reservoir ultimate recovery.Well Surveillance PlanningIn this section, IAM has been used to control, monitor and perform forecasting for each well. Potential well problem in the future have been predict and planned the appropriate solution through scheduled well intervention.Subsidence ManagementKLX/KLY produce from Carbonate build up reservoir with low rock compressibility. Subsidence phenomena have been observed; therefore, integrated reservoir management is very important in this area. Ultimate subsidence, facility remediation and subsidence effect have been investigated.

The purpose of this paper is to present the importance of IAM for KLX/KLY asset to ensure production continuation through the integrated engineering study on reservoir modeling, core analysis, facility remediation and effect of reservoir subsidence on gas production/reservoir performance and surface facility.
A Case Study of a Mature Field Redevelopment Using Propped Hydraulic Fracturing
Authors: Burnstad R. G. , Martin A. N. , Stemberger D. J. , Purwanto B.
Published: December 2007

This paper will detail how a mature oil field in the South Kalimantan region of Indonesia was revitalised by the use of hydraulic fracturing. The Tanjung Raya field is a complex, multilayered, mature oil field. This field was initially developed in the 1960's, with production peaking at over 55,000 bopd. By the mid 1990's, production had declined to less than 1,200 bopd. The introduction of a water flood increased production to a peak of 10,000 bopd, but this quickly declined at an average rate of circa 33% per year. With the introduction of a fracturing programme, based on treating existing and new wells, production has been maintained at a flat 7,000 bopd over the past two years. The hydraulic fracturing program has accounted for 80% of these significant production gains, adding more than 5.7 million barrels of recoverable reserves and extending the economic life of the field by more than 2.5 years.

Hydraulic fracturing is a process that is relatively underutilised in the Asia-Pacific region, as compared to North America, Latin America and the Middle East. With a couple of recent noticeable exceptions, the technique is either not considered during field development and redevelopment, or it is used on a one-off, remedial basis. However, fracturing can be an integral part of well design, and an effective tool when the technique is applied systematically by practitioners who understand its capabilities; as demonstrated in the Tanjung Raya field.

This paper will discuss how a significant increase in oil productivity from a mature field was attained with a very high propped fracture treatment success rate. It will also detail how the correct design of fracture treatments can enhance reservoir recovery rates, and fully utilise vertical wells as a low cost, effective alternative to horizontal wells, or to increase well spacing. The paper will also discuss the most significant issues of implementing such a program and how these issues were effectively dealt with in the Tanjung field.
Coiled Tubing Conveyed Fracturing System Allows Longer Zones to be Isolated in a Single Trip Multiple Times
Authors: Stricker Michael P. , Romano Frank J. , Simmons Rickey L.
Published: December 2007

Increased production and lower costs in shallow gas wells are closely linked to developing and refining new coiled-tubing drilling, completion, and production techniques. Innovations in coiled tubing have reduced the costs of drilling and completing these wells and increased their productivity and life cycles. Coiled-tubing fracturing is one such innovation. This has been used for some time now, predominantly in North American shallow gas wells. In these wells, the cost advantages associated with working over the well in a live condition while reducing job time are attractive.

Coiled-tubing fracturing operations usually employ straddle-type tool configurations. However, with a typical maximum lubricator length of about 30 ft, straddle interval lengths have been restricted, which increases the amount of resets required to effectively fracture individual zones. This restriction also increases the potential risk of communication above the assembly.

This paper describes the development of an economical and reliable coiled-tubing fracturing system that allows selective fracturing of previously bypassed pay zones. This is now possible because the system can be conveyed in a tandem configuration that works within current lubricator restrictions, but is capable of setting repeatedly as a retrievable bridge plug and treating packer combination. This allows longer zones to be precisely isolated multiple times in a single trip in hole.

This innovative technique can not only reduce intervention costs but also reduce the total time required to complete the operation. This paper examines a case history, with emphasis on pre-job planning, equipment selection, wellsite execution and post-job results.
A Unique Grid-Block System for Improved Grid Orientation
Authors: Chong E. , Syihab Z. , Putra E. , Schechter D.
Published: December 2007

The grid orientation effect is a long-standing problem plaguing reservoir simulators that employ finite difference schemes. A rotation of the computational grids yields a substantially different solution under certain circumstances. For example, in a five-spot pattern, the predicted recovery, water cut performance and the locations of the fronts depend on the type of grid system used. A Cartesian grid with one axis parallel to the line joining an injector and producer gives a solution significantly different from a grid that has the axes oriented at 45° to this line.

The objective of this study is to develop a grid system that can improve the representation of the configuration, thus minimizing the grid orientation effect. This paper presents a method for reducing the effect of grid orientation on computed numerical results in finite difference reservoir simulation. This method involves using a unique grid-block assignment where rectangular grid blocks are interspersed with octagonal grid blocks. The boundaries are then populated with triangular grid blocks. Thus, the entire domain will consist of a "structured" grid block system referred to as the Hybrid Grid Block (HGB).

To test the viability of HGB, a finite difference IMPES-formulated two-dimensional black oil simulator was developed in this study, while retaining the familiar finite-difference discretization of the flow equations. Simulation cases were conducted to further examine the grid orientation effect in conventional grid block systems. Then, similar cases are run using HGB grid system. The outcome shows that HGB gives very close agreement between the parallel and diagonal grid orientation. This innovative grid block assignment will help to reduce the grid orientation effects compared to conventional grid block system.
New GTL Process - Best Candidate for Reduction of CO2 in Natural Gas Utilization
Authors: Suehiro Y. , Ihara M. , Katakura K. , Nakamura A. , Sakamoto A. , Kawazuishi K. , Kajiyama R. , Fujimoto K. , Ohnishi Y. , Okado H. , Shimizu T.
Published: December 2007

Japan Oil, Gas and Metals National Corporation (JOGMEC), which is a former Japan National Oil Corporation (JNOC), has been developing natural gas to liquids (GTL) conversion technology since the year of 1998 in collaboration with five private Japanese companies, namely; JAPEX Co. Ltd., Chiyoda Corp., COSMO Oil Co. Ltd., Nippon Steel Corp., and INPEX Corp. Our new GTL process is particularly effective when it is applied to natural gas feed stock containing 20-40mol% of CO2. It does not require the three expensive items; (1) an oxygen supply plant, (2) a unit for CO2 separation from natural gas, and (3) a H2 separation unit to optimize gas composition. The reduction of these facilities, which are indispensable to the conventional GTL process, would results in less CAPEX and OPEX.

For our new GTL process, the most preferable CO2 content in feed natural gas is around 30mol%. Therefore, in case that the CO2 content is less than 30mol%, some amount of CO2 can be supplied from other CO2 sources, such as flare gas, associated gas, remaining CO2 of EOR and exhausted gas from oil refinery and LNG plant.

This paper aims to present applications of our new GTL process to enable an economic exploitation of gas reserves in South East Asia and Australia, by taking into account the operation results of the Yufutsu GTL pilot plant of 7BPSD located at Tomakomai city in Hokkaido of Japan, and the study results of process simulation and the economics. We present an attractive combination scheme for our new GTL process with LNG plant by utilizing CO2 exhausted from LNG plant. It reduces initial project's investment compared with a stand-alone GTL plant located in South East Asia and Australia, where infrastructure of an LNG plant can be for common use with our GTL plant.
Optimisation CO2 Removal Design for Block B-17 in the MTJDA
Authors: Chenboonthai Nuntasak
Published: December 2007

Nine gas fields have been discoved in Block B-17 in the Malaysia-Thailand Joint Devepment Area (MTJDA). Most of them have high CO2 content which makes the gas unmarketable. To achieve the commerciality, CO2 content needs to be reduce to the level that the existing market is able to accept the Block B-17 gas. Under the GSA-HOA which had been signed in 1999 between Buyers and Sellers, it had specified the CO2 content not more than 23 mole%. Therefore, the Sellers need to design the gas processing facilities to meet the requirement of Buyers. Generally, the value of sales gas is based on its heating value, not volume. The high CO2 content means the less heating value resulting the less revenue. Therefore, the Sellers must reduce the CO2 content in sales gas as low as possible. Paradoxically, the more removal of CO2 content in sales gas does not indicate the best economic results, due to the high investment cost. To optimise the project economic, the percentage of CO2 content has to define under the specification of GSA-HOA and economical consideration of the project. Several factors, for instance, gas compositions, reserves, well deliverability, need to be taken into the account of the processing design.

In order to achieve the maximum benefit, the CO2 removal optimisation has to be properly designed. This paper will present a model which describes the relationship between values of sales gas and the CO2 removal cost resulting in i) good economical regime with available raw gas quality in the Joint Development Area (JDA), and ii) raw gas mixture for optimum sales gas heating value which relates to economic design of the CO2 removal.
Pressure Activated Deployment of Openhole Memory Logging Tools Into Directional Wells and Past Bad Hole Conditions
Authors: Spencer M. C. , Ash S. C. , Elkington P. A. S.
Published: December 2007

Openhole memory logging was introduced in 2000, initially as a more efficient alternative to pipe conveyed quad-combo wireline logs in high angle and horizontal wells and wells with bad hole conditions. By 2001 a range of deployment techniques had been developed that provide high-quality, low-cost, post-drilling formation evaluation logs to supplement basic real-time data (such as navigation and gamma ray). Among the new techniques is a shuttle system that conveys memory tools rapidly to TD inside drillpipe, ideally as part of a wiper or check trip. In one manifestation a dart pumped from surface releases the logging string after the assembly reaches TD, then moves the string from the drillpipe into open hole. This variant has been successful in over 350 wells. In a new development the dart has been eliminated, replaced by an electro-mechanical pressure activated release mechanism that eliminates the dart pumping time, has better power management for longer operations, and is capable of simple two-way communications – a key element in a repeat formation pressure tester being developed for memory operations. A slim variant operates in wells down to 4 1/4-inches bit size.
Blending Formal and Informal Learning Offers New Competence Development Opportunities
Authors: Collis B. A. , Margaryan A. , Kennedy M. W.
Published: December 2007

A shift from content-based to activity-based learning is taking place at the Shell Open University (SOU), with already more than 100 course events redesigned from a classroom only model to this new model. It emphasizes work-based activities, supervisor involvement, and sharing of knowledge and experiences via a blend of formal and informal learning. Results to date and lessons learned are presented.
Independent Environmental Data Verification: Views and Experience
Authors: Tan G. T. , Al Riyami M.
Published: December 2007

This paper described the independent environmental data verification process undertaken by Petroleum Development Oman (PDO). It was an opportunity to demonstrate external assurance process for environmental data integrity and hence improve PDO's reputation. It ensured a disciplined and structured process to data gathering and management as well as providing valuable learning to staff during the verification process.

The financial methodology used for the verification need some modifications to make it more suitable for environmental data verification. Verifiers who have knowledge of the technical nature of environmental data gathering and management are critical to the success of the verification.