bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Technologies Enhance Operational Efficiency in Difficult Gravel-Pack Operations
Authors: Lima Everaldo , Pounds Rob , Borin Gustavo Ribeiro , Pereira Alexandre Zacarias Ignacio 
Published: December 2007

Abstract
Although extended reach and horizontal wells in deepwater fields have presented many difficult challenges, operators have been willing to accept the challenges because of the substantial net reserves that the deepwater fields offer. Unfortunately, although promising new technologies that target the more extreme conditions inherent to deepwater completions have been introduced, many operators have hesitated to try them because they lack proven track records. Fortunately, this has not been the case with one operator, and this paper will discuss the innovative technologies that were employed to successfully perform two "firsts" in gravel pack completions in complicated wellbore scenarios in a deepwater subsea field.
The first job is the longest deepwater horizontal gravel pack (HZGP), run in Brazil. 75,000 pounds of gravel was placed in a 2,730-ft openhole section in 2,621 ft of water from the Ocean Alliance rig. The technologies that were instrumental in the success of this completion included special packer technology, a multi-position weight down tool with a HZGP pressure maintenance assembly, and a new type of sand control screen. Despite the long slant section (6560 ft @ 60 degrees) and openhole length, installation of the sand control completion was smooth, never reaching more than 10,000 pounds of drag.
The second job used a realtime operations (RTO) data acquisition and visualization system during a gravel pack procedure. The system employs advances in traditional data management and networking to allow the personnel at the wellsite as well as all remotely stationed personnel to monitor critical well parameters so that immediate decisions on procedural changes can be made. The system allowed the service personnel and operator to monitor the job's execution and adjust pumping parameters as needed. This job illustrates the enhanced capabilities that can be gained from adapting innovative techniques to traditional procedures.
The best practices from these completions will be used in all future jobs. This paper illustrates the importance and gains possible from considering new technologies and applying them where feasible.
Apache Energy – Knowledge Management System
Authors: Attwell Shane , Moses Michelle 
Published: December 2007

Abstract
Apache Energy has implemented a system which provides data from real-time well head process data to continuous month to date production information available to head office and joint venture partners over the internet.
Apache is one of the largest gas produces in Australia with assets in Australia and overseas. There are several different Joint Ventures (JVs) involved in the various fields and processing plant. The operations are spread between Offshore, Varanus Island, Perth and Houston. Joint venture partners are located in Adelaide, US, Perth and Kuwait and gas customers are located throughout Western Australia. Such diversity requires effective information distribution.
Over the last 5 years, Apache has implemented a process information management system, which enables production data to be transmitted securely all over the world, minutes after the end of each production day.
Production data business flow commences with Apache's customers placing orders or "nominations" via the web based gas nominations system. The nominations are validated against the customer contracts, collated and the total gas production for the day is electronically issued to the operator. At the end of the gas day, production, well, and facility performance data is collected automatically and presented to the operator for validation. Once validated by operations, the data is loaded into the Production Reporting System (PRS) database and a series of applications are executed such as; Well allocationSales gas reconciliationJoint Venture partner splits.Environmental calculations
The data is then released to the Apache users and the Joint Venture partners shortly after the end of the 08:00 production day. The data is also released on to the Internet under a security system which allows Joint Venture partners to view production, inventory/lifting and monetary splits between the JVs for the month. Environmental reports are issued to the government via internet pages. In addition to production data, the system provides engineers and management with remote adhoc real-time process data.
Use of this system has enabled the engineering groups to identify well problems resulting in production benefits. Apache has been able to significantly reduce the amount of time required to provide JV reports and JV payments and double handling of data has been virtually eliminated. The goal of entering data once, at the source, has largely been met.
This paper will address the processes and business benefits Apache have observed from this knowledge management system.
Real Time Geosteering of High Tech Well in Virtual Reality and Prediction Ahead of Drill Bit for Cost Optimization and Risk Reduction in Mumbai High L-III Reservoir
Authors: Mitra Partha P. , Joshi T. R. , Thevoux-Chabuel Hugues 
Published: December 2007

Abstract
The Geosteering of high tech horizontal wells through thin reservoir sections is always a challenge. If the entire operation of real-time LWD Geosteering is monitored in a virtual reality environment, a near reality wellbore drilling situation can be simulated through stereoscopic projection within a modeled reservoir for better understanding and interpretation of a complex problem. This has significant benefits in reducing the rig wait time for critical decisions. Additionally, it provides the tremendous advantage of using the expert multi-disciplinary team at the base thus reducing the risks of drilling a less than optimal well.
The Mumbai High L-III reservoir is a highly heterogeneous multilayered carbonate reservoir on the continental shelf of western India in the Arabian Sea. As a part of ongoing redevelopment program, multiple horizontal wells are being drilled through thin productive layers. This paper describes a successful Geosteering application using the latest technologies to transfer, edit and analyze information in real time. Real-time LWD data were transmitted via the INSAT 3B satellite from the offshore drilling rig to the Virtual Reality Centre in Mumbai City, India. Seamless sharing of data between the service company and the Reality Centre was achieved using the recent WITSML 1.2 data transfer standard. Real-time LWD, seismic and drilling data were integrated to monitor the drilling progress. A pre-defined geological model was used to model the LWD data. The planned and actual well trajectories were continuously updated while drilling. The geological model was updated based on the comparison between real-time and modeled logs. Instructions regarding mid course corrections were conveyed to the drilling engineer at the rig. The technology helped to optimize the well path, maximize the productive interval and avoided unproductive rig time.
Balancing Recovery of Upside Reserves Against Subsurface Uncertainties, West Patricia Field, Offshore Malaysia
Authors: Prasetyo Teguh , Lasman Mohd. Reza , Firth Andy , Jamiran Mohd. Khalid 
Published: December 2007

Abstract
Oil was discovered at West Patricia Field in December 2000, thirty-seven years after the first exploration well was drilled. A fast track three-well appraisal and six-well development program followed the discovery, which led to oil production in May 2003.
The initial interpretation of logs, core and image data from the first four exploration and appraisal wells suggested that the West Patricia oil reservoirs were deposited as stacked channel sands in a lower coastal plain setting. However additional data from wells drilled during the initial phase of development, suggested that these reservoirs were more widespread and that they were stacked river mouth bar sands deposited in an estuarine lagoonal setting. This change in depositional concept has resulted in a reserves increase of 50%, which led to an increase in development scope in order to ensure optimal reserves recovery. A field development plan was recently concluded to further develop the field in 2004.
Despite this upside, several uncertainties remain. Pressure data and fluid distribution indicate that the field could be more compartmentalized than can be interpreted from seismic and that multiple gas-oil-contacts and oil-water-contacts may be present.
This paper describes the integration of sedimentological, stratigraphic and fluid pressure data to optimize reserves recovery from the West Patricia field whilst managing the remaining uncertainties.
A Three-Phase Non-Darcy Flow Formulation in Reservoir Simulation
Authors: Su HoJeen 
Published: December 2007

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.