bluuebunny/crossref_metadata_2025_split huggingface dataset:
Achieving Low Cost Operation in Mature Oil Fields
Authors: Pasni Imelda , Wibowo Ignatius T. 
Published: December 2007

Abstract
The most challenging problem in mature oil fields is how to continue operating in a low cost fashion as crude production continuously decreases. To survive, companies need to realistically look at ways to rationalize their assets, which include rearranging operation modes or suspending some production facilities to achieve desirable asset value.
Offshore North West Java Production Sharing Contract (ONWJ PSC), is located in the Java Sea, Indonesia. It has been on production for almost 30 years and currently has about 150 production platforms, 700 production wells and more than 1,000 miles of sub-sea pipelines. Peak crude production was approximately 180,000 BOPD but currently it produces less than 70,000 BOPD. This paper describes efforts in the ONWJ PSC to reduce cost by using K-Flowstation, one out of thirteen flowstations in the contract area, as an example. This flowstation has been on production for more than 25 years and consists of three producing platforms, one process platform and one compression platform. A drastic cost reduction was achieved by restructuring the operation mode in Kilo Flowstation. This success depended on the good cooperation among Engineering, Production and Shared Technical Services Group in embracing a new operating philosophy for Kilo Flowstation. In early 1999 the team targeted a direct cost reduction of 75% by end of year 2000. In reality, 60% of the cost reduction target was realized in 1999.
Probabilistic Addition of Reserves - A New Approach
Authors: van Elk Jan F. , Vijayan K. , Gupta Ritu 
Published: December 2007

Abstract
For multi-field projects, the total project ultimate recovery (UR) at a given confidence level is traditionally derived by the arithmetic addition of the UR's of its constituent fields. However, this overstates the uncertainty range at the total project level. The total project UR, at a given confidence level, is more correctly derived by probabilistic addition (PA) of the field UR's. As Probabilistic Addition requires the definition of the dependencies between the added elements, it is important that UR dependencies between fields are correctly estimated and incorporated into the calculation of the total project UR.
This paper introduces a new statistically rigorous method for estimating UR dependencies between fields and for Probabilistic Addition of the field UR's to project level.
The UR dependencies between fields are estimated based on the field UR sensitivity to field parameters, as commonly summarised in the UR Tornado Diagram. This data is routinely generated when the Multiple Realisation Approach is used to derive reserves estimates in a field study.
The method of Probabilistic Addition is based on the assumption of Multivariate Normality. The method is very efficient in capturing field dependencies and eliminates the need for Monte Carlo simulation. Additionally, the method allows for a sensitivity analysis of the generated project UR, to the estimated field UR correlations.
In this paper, the application of the methodology to an actual project case is presented. The Probabilistic Addition of the North West Shelf gas-condensate fields producing into a shared onshore domestic gas and LNG plant is discussed. The North West Shelf project reserves at P90 confidence level, calculated using Probabilistic Addition, are significantly larger than the arithmetic sum of the P90 reserves of the constituent fields.
Novel Technique for Openhole Abandonment Saves Rig Time-A Case History
Authors: Chong King K. , Butterfield Charles A. , Conwell Russell P. 
Published: December 2007

Abstract
This paper presents a method for setting a competent cement plug over a long section of open hole in a deviated development well. The offshore operator saved 12 to 15 hours of rig time and used significantly less cementing material, such as surfactants and spacers for ester-base mud (EBM) removal. The modified procedure saved approximately $200,000 U.S. in rig time and materials.
The plugback job involved setting a competent cement plug over a 600-m interval of 8 ½-in. appraisal section drilled below 9 ⅝-in. production casing. The conventional procedure to plug back this hole section involves setting three or four long cement plugs on top of each other from total depth (TD) into the 9 ⅝ -in. shoe. If used in the case history situation, the conventional method would have exposed the EBM in the hole to a high risk of cement and spacer contamination. In this case history, a modified procedure was designed so that the full openhole section could be cemented with a single cement plug, minimizing the risk of mud contamination and helping ensure a positive top of cement (TOC) inside the 9 ⅝-in. casing shoe.
The new procedure involved running a long stinger of old, 3 ½-in. tubing on a modified bottomhole kickoff assembly (BHKA) tool, which allowed the stinger to be released from the drillpipe after the single cement plug was set. Because the tubing had been written off, it was used at no cost. The main benefits of this modified abandonment method included (1) minimal disturbance of cement (no need to pull the cement stinger through the plug), (2) minimal contamination of the EBM, and (3) reduced rig time and material cost compared to setting multiple plugs.
Techniques presented in this paper may be used in most instances that require placement of long, openhole cement plugs for hole abandonment.
Impact of Multi-Disciplinary Team Approach to Design Stimulation Treatment for Bombay Offshore Basin
Authors: Haldar Surajit , Nainwal S. P. , Bhatnagar S.B. L. , Bhatta M. K. 
Published: December 2007

Abstract
Many studies have been done on stimulation of carbonate reservoirs. Various techniques are also applied to stimulate the carbonate reservoirs of Bombay offshore basin. Though, use of conventional acidizing techniques are predominant in these fields, application of new stimulation techniques are also done but none have an effective impact on the productivity.
Well stimulation by and large involves knowledge and participation of many departments. This paper describes how the multidisciplinary team approach has made a significant change to overcome the challenges together with the resulting technology development.
Comprehensive studies were done to evaluate the formation in association with geophysicists, geologists, reservoir engineers, chemists and production engineers. Detail formation and core study confirmed that not only long fracture length but also the formation needs effectively etched longer fracture length to improve the conductivity. Multi-layered heterogeneous formation pattern also restricts the acid from deep penetration into less permeable area.
The proposed stimulation technique has two important components: acid placement technique and improved acid system. In this technique the formation is fracture acidized in multiple stages for longer fracture length. Followed by that a closed fracture acidizing enhances the permeability. An improved acid system maintains the acid concentration at different part of the fracture by varying the acid retardation resulting in effective etching and deep penetration. Field results verify this technique. This paper compares this stimulation technique with other stimulation treatments done in the Bombay offshore basin, where this new technique is applied. Lab results are included.
The focus of this paper is the process of candidate well selection for suitable stimulation treatments, to achieve more etched fracture length, and finally innovation and creation of value through team approach.
Mobility Control by Polymers Under Bottom-Water Conditions, Experimental Approach
Authors: Shirif Ezeddin 
Published: December 2007

Abstract
In many light or moderately viscous oil reservoirs in Saskatchewan and Alberta, a high water saturation zone ovarying thickness and extent ("bottom-water zone") occurs in communication with the oil zone above. As a result, the primary production period is short, and water coning occurs very early in the life of the reservoir. Later, during the secondary recovery stage, such a zone can have an adverse effect on the waterflood efficiency. This research addresses the problem of waterflooding such reservoirs.
This study was directed towards reducing water mobility in the bottom-water zone for more efficient oil displacement. Polymer in various concentrations was used as a blocking agent in the bottom-water zone and as a mobility control agent in the oil zone. Different strategies were investigated to reduce the water mobility in the bottom-water zone and improve the vertical sweep efficiency. The variables examined were: relative water-oil layer thickness, oil viscosity, polymer concentration, injection rate and injection point, as well as the effect of vertical and horizontal injection and production wells.
The results showed that oil recovery could be increased by minimizing crossflow between layers by blocking the bottom- water zone completely. It was also found that for an unfavourable mobility ratio, as the injection rate increases the ultimate oil recovery increases. The injection of a polymer solution had a favourable impact on waterflood performance. Moreover, the worse the conventional waterflood performance was, the more effective the polymer was as a mobility and blocking control agent. The use of horizontal wells showed slightly better oil recovery over vertical wells in a conventional waterflood of reservoirs under bottom-water conditions. In addition, some certain well combinations (horizontal production and vertical injection) gave better oil recovery due to the increase in the swept area.
Improved Oil Recovery of Edge and Bottom Water Reservoir by Drilling Horizontal Sidetracks
Authors: Hongyin Zheng , Peimao Zhang 
Published: December 2007

Abstract
This paper presents the important effects of slowing down the oil production decline, increasing the sweep efficiency and improving the oil recovery by drilling horizontal sidetracks for the Huizhou 21-1, Huizhou 26-1 and Weizhou 11-4 oilfields in the South China Sea. And also analyzes the production performance of the eight horizontal sidetracks and the development effects in detail.
According to the practical production experience, it is economically and technologically feasible to produce the remaining oil and to improve the oil recovery by the sidetrack drilling technology during the middle and later production periods for the mature oilfield. The oil production rate of these eight horizontal sidetracks for single well is more than 2-3 times that of the average oil production rate of conventional well in the same reservoir. It indicates that this method has great potential and wide applying prospect to improve the development effect for sandstone reservoirs with strong edge and bottom water drive, especially during the middle and high water-cut periods. And also it is recognized that the accurate reservoir characterization and the detailed study of remaining oil in place are the basement for geological design of the horizontal sidetracks and can ensure success of the drilling.
Remote Controlled (Tether-Less) High Pressure Isolation System
Authors: Tveit Edd , Aleksandersen Jostein 
Published: December 2007

Abstract
The PSI SmartPlug is designed to isolate high pressure inside pipelines and risers, thus permitting pipeline maintenance and repair without losing the contents and without the need to flare, depressurise or decommission the pipeline. Use of this tool to isolate pressure also allows dry laying and tie-in during construction of new pipelines.
The PSI SmartPlug comprises two Plug Modules, each of which is currently designed to withstand the full MAOP (Maximum Allowed Operating Pressure) differential pressure. Two bi-directional Pigging and Control Modules at each end of the SmartPlug ensure suitable pigging characteristics. The tool is designed to traverse minimum bend radii of 1.5D. The Control Module contains a hydraulic system with valves, battery pack, computer hardware and software, as well as an antenna that enables through-pipe wall communication.
An Extremely Low Frequency (ELF) Subsea Communication Link sitting on the seabed outside the pipeline ensures through-wall communication with the SmartPlug inside the pipeline. An acoustic link ensures command and information transfer between the topside computer and the SmartPlug. The topside operator sends instructions to set and unset the SmartPlug, in addition to monitoring various parameters such as pipeline pressure, annulus pressure and status of the tool. The system is based on reliable off the shelf standard components and designed to ensure redundancy as required.
The Prediction of Cloud Point Temperature: In Wax Deposition
Authors: Sadeghazad Ayoub , Christiansen Richard L. , Sobhi G. Ali , Edalat M. 
Published: December 2007

AbstractThe main object of this paper is to evaluate and discuss the cloud point temperature dependence on the solution nature in the crude (oil). Also, a correlation was developed for predicting the cloud point temperature in wax deposition.The cloud point temperature is an important parameter to see weather there will be precipitation or not. So, we interested on the parameters that affect the cloud point temperature of hydrocarbons. Therefore, besides literature survey, some experiments on wax/paraffin deposition have been performed and evaluated.Based on our experimental observations, the most important parameters that affect the hydrocarbon cloud point temperature are the apparent molecular weights of solution and solute, and solute weight fraction. These are the basic parameters of our developed correlation. Through the regression process different equation types have been used and a complex nonlinear poxlynomial type was selected to obtain a correlation which predicts the cloud point temperature with less than 1.0- percent error.Our developed correlation is the only analytical solution for the prediction of cloud point temperature in wax precipitation. It also works for pure alkanes. This modeled correlation is ver simple to use and less time consuming. In addition, its results are very precise and more accurate than the previous models.
Oil and Gas Separation Theory, Application and Design
Authors: Katapodis Leon 
Published: December 2007

Introduction
The physical separation of fluids is the most basic and necessary segregation in oil and gas processing. An oil and gas separator is one of the most fundamental pieces of production equipment used. Because of its production equipment used. Because of its front end position in on-stream processing, its performance is vital to the operation of a production facility. Oil and gas separators were one of the first pieces of production equipment introduced in the oil industry. But regardless of this longevity, the separator has not lost any of its original and vital importance in the separation of liquids and gases. This paper will discuss on a limited basis some, but not all, of separator design considerations.

DESIGN REQUIREMENTS
at the pressure and temperature within the vessel.
Assume proper control, by devices which will provide for the removal of this separated liquid phase from the vessel without allowing an opportunity for re-entrainment of one phase into the other.
All separators, whether vertical or horizontal, to achieve the functions listed above, consist primarily of four (4) basic sections.
The Development of Emulsion-Based Production Chemical Deployment Systems
Authors: Collins I. R. , Jordan M. M. , Feasey N. , Williams G. D. 
Published: December 2007

AbstractIn this paper we describe the development of a novel water-in-oil emulsion system for the deployment of aqueous-based production chemicals. The non-aqueous nature of the emulsion system potentially allows ingress of the chemical into parts of the reservoir normally denied access to an aqueous-based formulation and so can improve contact between the chemical and the reservoir fluids on production. Furthermore, the whole treatment can be deployed as a non-aqueous package allowing oil continuity to be maintained during the treatment. This can (i) prevent changes in the near well-bore relative permeability arising from the influence of the injected fluids; (ii) prevent water becoming trapped in oil-bearing zones reducing permeability to oil; and (iii) improve production chemical penetration depths (the water-wet nature of sandstone reservoirs means that the penetration depth of, for example, scale inhibitor solutions can be low). Moreover, for poor pressure support reservoirs, the reduced density of a non-aqueous treatment can obviate the need for artificial lift to restart the well. Originally developed for scale inhibitor deployment, this technology has been advanced by developing slowly degrading emulsion systems, which provide a means of trapping the aqueous production chemical within the porous media and allowing subsequent controlled release of the chemical. This advanced scale control technology has been proven in the laboratory for the encapsulation of corrosion inhibitors, biocides, hydrogen sulphide scavengers, and chemicals for the control of reservoir souring. Encapsulated scale inhibitors have been field deployed in two locations (in the UK sector of the North Sea and in the demanding environment of onshore Alaska under both high water cut and very low water cut conditions). This paper describes laboratory testing, including coretests, and describes the planning, the execution, and the results of the field treatments.
Use Of Water Base Spacer With Thixotropic Cement Solves Varied Cementing Problems
Authors: Griffin T.J. , Calvert D.G. , Parker D.L. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Thixotropic cements are cement slurries which are thin when mixed and pumped, gel rapidly when pumping stops, and become fluid if pumping is resumed within a short time. They have pumping is resumed within a short time. They have found wide application in the solution of many difficult cementing problems since they are self-supporting and have expansion properties. Until recently it had not been possible to control water loss of these systems due to their incompatibility with commonly used water loss control additives. A new approach to this problem has resulted in reduced water loss from the thixotropic cement slurry by means of a water base spacer being run ahead. The water loss of the water base spacer is designed to allow use of the thixotropic cement slurry in these conditions where water loss control is needed or desired.
This paper describes thixotropic cements, their uses, and techniques of application. Development of the water base spacer and its effect on thixotropic systems is also described. Comparative results show how improved well production can be achieved with use of the spacer and production can be achieved with use of the spacer and thixotropic cements.

Introduction
During the Past few years, a number of factors have been studied both in the laboratory and field application to improve the primary cement job. Some of the factors: pipe movement, position of pipe, use of a water loss controlled cement slurry, use of a spacer to separate mud and cement, and use of a cement slurry that exhibits expansive characteristics after setting. The use of a thixotropic cement has found use in most all areas because of its unique properties. properties. The application of all the aforementioned factors have not been possible because the commonly used water loss control additives destroy the thixotropic properties of the desired cement slurry. Research efforts to date have not allowed the development of an adequate water loss control additive, therefore the possibility of using a spacer with excellent water loss control ahead of cement slurry was studied. The filter cake laid down must not only be adequate to control water loss of cement slurry, it must have properties that are applicable to a well designed properties that are applicable to a well designed spacer system. Some of these are:Compatible with both the drilling fluid and the cement system.Low water loss.
Discussion on Integrating Monitoring Data into the Reservoir Management Process
Authors: Rossi D. J. , Gurpinar O. , Nelson R. , Jacobsen S. 
Published: December 2007

Abstract
Optimum management of oil and gas reservoirs is a continuous, iterative process which encompasses monitoring the reservoir, interpreting the monitoring data, and deciding from the results how best to continue reservoir development and executing those decisions. Monitoring data vary widely in time and space scales. Temporally, they range from continuous to infrequent, episodic measurements; spatially, they range from local well-centric to global reservoir measurements.
The reservoir management workflow similarly operates at multiple, parallel time-space scales. A "fast" workflow loop handles continuous well and surface network data (e.g. pressure, temperature, and rate), using fast data handling and fast decision-making to optimize hydrocarbon delivery. A "slow" workflow loop assimilates episodic reservoir data (e.g. time-lapse seismic and borehole reservoir measurements) to optimize reservoir drainage.
Reservoir monitoring data are assimilated at the most appropriate time into the reservoir shared earth model, which feeds both the "fast" and "slow" workflow loops. A continuing industry challenge is to determine the best way to do this, since the types of monitoring data are diverse and the volume of data to assimilate is often vast.
This paper begins with a review of reservoir monitoring data that are available today, with a focus on the range of time-space scales. A reservoir management workflow is introduced which has multiple time scales appropriate for these data. The paper concludes with a review of key challenges: (1) to develop improved interpretation technologies to unify and integrate the fast well-network centric and slow reservoir-centric workflow loops for faster conversion of measurement signals into information, and (2) to provide fuller support for uncertainties, including determining how the level of uncertainty in the reservoir model changes when assimilating monitoring data.
Integrated Downhole Monitoring of Hydraulically Fractured Production Wells
Authors: Bell Matt , Kraaijevanger Hans , Maisons Christophe 
Published: December 2007

AbstractThe first phase development of the Athel formation in South Oman relies on massive hydraulic fracture stimulation to realise economic production rates from micro-Darcy rock. It has been recognised that the size, shape and direction of the hydraulic fractures are key parameters in the prediction of well performance, optimum well placement and optimisation of fracture design.In view of the highly laminated, intensely structurated geology, an early assessment of flow barriers and dynamic reservoir behaviour will also be crucial to managing long-term recovery of the significant Athel reserves.In order to acquire substantial data addressing each of these issues, an integrated permanent downhole data acquisition system (PDDA) is being installed in the Phase I production wells. The system utilises a unique combination of tubing conveyed gauges and triaxial geophones to deliver real-time bottom hole pressure/temperature and microseismic data throughout both stimulation and production.The first well equipped with the PDDA system was fracture stimulated in May 2000. This paper presents initial results, including interpretation of the microseismic data to determine fracture azimuth and dimensions.The ongoing PDDA project, leading to integration of microseismic data recorded in offset wells and the acquisition of long-term flowing bottom hole pressure and build-up data is also discussed and comments made on the general oilfield applicability of such systems.