bluuebunny/crossref_metadata_2025_split huggingface dataset:
Determination of In-Situ Precipitation of Barium Sulphate During Coreflooding
Authors: McElhiney John E. , Sydansk Robert D. , Lintelmann Kurt A. , Benzel William M. , Davidson Kimberly B. 
Published: December 2007

Abstract
In-situ barium sulphate precipitation was observed during coreflooding experiments conducted at frontal velocities of 0.31 m/day in fired Berea sandstone cores. The precipitate was observed during a laboratory study on the transport of sulphate ions contained within the injection water that displaced a synthetic formation water containing barium ions. Two separate cores were 100% saturated with formation water similar to that of a West African offshore reservoir (240 ppm barium and 230 ppm strontium) and were respectively flooded with synthetic seawater containing 2860 ppm sulphate and synthetic low-sulphate (desulphated) seawater containing 36 ppm sulphate. Careful measurement and comparison of flood effluent profiles of precipitating and non-precipitating ionic species such as sulphate, barium, strontium, etc. indicates that barium sulphate precipitated in situ during the flooding experiments. In the case of the seawater flood, approximately 27% of the barium that was contained in the formation water resident in the core was precipitated. In the case of the low sulphate seawater flood where the propensity for barium sulphate precipitation was low, results were less dramatic and determination of the exact amount of precipitated barium sulphate was less certain, e.g., approximately 10% of the barium was precipitated. Temperature and pressure conditions for these coreflooding experiments were ambient temperature (~70°F) and atmospheric pressure. The Berea cores utilized were 5.08 cm in diameter, 15.2 cm long, and averaged 112 md permeability and 17.5% porosity.
Results of this coreflooding study indicate that in-situ precipitation of barium sulphate occurs while even low-sulphate seawater is flooded through core material that is saturated with a formation water containing barium. During reservoir-scale flooding with low sulphate seawater, a favorable consequence of the barium sulphate precipitation is that the sulphate scaling potential is substantially reduced at the producing wells. This work represents a first step in generating experimental data that can be input into a mathematical simulator for predicting the propagation rate and the breakthrough time, under reservoir conditions, of the sulphate ions of the injection water -- both for low and high sulphate content injection waters.
Coiled Tubing Seismic While Drilling
Authors: Jackson T. S. , Gorrara A. J. , Chmela W. 
Published: December 2007

Abstract
The efficient exploitation of hydrocarbon resources is strongly dependent on the drillers’ ability to position wells accurately. This is particularly challenging for smaller targets and on long reach or horizontal wells. Conventional wireline VSP's can provide valuable assistance but such operations require either the drill string to be removed from the hole or the pumping of the geophone tool through the drill string. Both of these methods add time to the well construction. In long sections of open hole wireline operations may present risks, in the form of sticking and potential fishing operations, which prevent VSP surveys being acquired in lookahead mode. Ideally, VSP data would be acquired at several stages of the drilling process to enable corrective action to be taken to assist accurate bit placement. The costs in terms of rig time alone generally make this option prohibitive.
Ongoing developments for cost effective exploitation of mature and pressure-depleted reservoirs have led to wider applications for coiled tubing drilling. The combination of a seismic tool with the coiled tubing drill string therefore provides an ideal configuration to reduce drilling costs and optimise well placement. This paper discusses the conventional methods available for geosteering of the bit, the additional benefits of incorporating a seismic tool into the drill string and describes the development of a seismic while drilling tool (SMWD) for coiled tubing drilling.
Chemically-Enhanced Drilling With Coiled Tubing in Carbonate Reservoirs
Authors: Rae Phil , Di Lullo Gino 
Published: December 2007

Abstract
There has been a dramatic increase in the use of continuous reeled tubing (coiled tubing) for drilling operations. Much of this increase can be attributed to improvements in the quality and dimensions of coiled tubing itself – pipe sizes have steadily increased over the years from 1 inch OD to 3 V inch OD and bigger. Other developments have included improved downhole motors and, for directional work, sophisticated survey and orienting tools that can be controlled, in real time, from surface.
Despite these developments, CT drilling is still applied to very few wells, or a tiny percentage of the total drilling market. There are many reasons for this including high equipment and personnel costs, low rates of penetration (ROP), and issues related to the reliability of high-cost "smart" bottom hole assemblies (BHA's) needed for directional work. The idea that CT drilling would offer a cheap alternative to conventional rigs is, and probably will remain, an unfulfilled pipe-dream. However, CT drilling certainly has its place, particularly for vertical well deepening and for slimhole multilateral work. The method presented here provides the opportunity to improve the efficiency and lower the cost of such operations.
This paper describes a technique that we call Stimulation While Drilling (SWD), a drilling method that is particularly applicable to the use of coiled tubing. In particular, the method is intended for use in the drilling of multiple short, lateral drainage holes originating in the main borehole and extending outward radially through the reservoir, at one or several depths. However, any hole, including the main borehole itself, can be created using this technique, depending on the lithology. This ability to make large multilateral conduits, at high speed, in underbalanced conditions, if desired, and with no drilling damage offers significant advantages for well construction and completion, particularly in hard carbonate reservoirs.
Pushing the Boundaries of Coiled Tubing Applications
Authors: Sumrow M. H. , Economides M. J. 
Published: December 2007

Abstract
This paper offers a critical review of the capabilities and limitations of coiled tubing as used in matrix stimulation. A method to determine the effective reservoir thickness that can be treated, as a function of coiled tubing size, wall thickness, yield strength, length and well depth is outlined. The method allows the user to push the boundaries of coiled tubing applications to its practical limits.
The Responsiveness of Global E&P Industry to Changes in Petroleum Prices: Evidence From 1960 – 2000
Authors: Inikori Solomon O. , Kunju Mahendra Kumar , Iledare Omowunmi O. 
Published: December 2007

Abstract
Perhaps no industry has witnessed a more cyclical activity than the petroleum industry! Oil and natural gas account for a substantial part, over 70 percent, of world energy demand and utilization beside the worldwide application of its by-products. It is the main source of foreign exchange earnings for many developing economies.
Crude oil price volatility, especially in the recent past, has made decision-making and strategic planning extremely difficult for oil companies. Oil companies have responded to the low oil prices by reducing research and development budget, capital spending, and employment pattern. The operators are even more cautious than ever before in capital spending and expansion despite the current rising trend in crude oil prices.
This paper uses the basic laws of demand and supply and the concept of elasticity as well as user cost relations to evaluate the responsiveness of oil industry activity to changes in oil and natural gas price from 1960 to 2000. It relies on some E&P industry performance measures to evaluate the state of the oil and gas industry in response to crude oil price variability and instability. The results show that the profit margin of the major operators have been on the decline since the advent of OPEC and so is the demand for labor in the industry. The consequences of price instability have led to mergers and acquisitions and internal re-organization in order to attempt to maximize profit in the past few years. Finally, the paper attempts to forecast future oil and gas prices and evaluate their effects on oil industry activity over the next decade using economic impact analysis and the economic concept of price elasticity.
Design and Implementation of a Horizontal Injector Program for the Benchamas Waterflood - Gulf of Thailand
Authors: Graves K. S. , Valentine A. V. , Dolman M. A. , Morton E. K. 
Published: December 2007

Abstract
The Benchamas Development in the Gulf of Thailand is an oil play in a predominantly gas-condensate region. This development is unique in that the operator has significant oil reserves of high pour-point crude in several zones. Some zones have gas caps; others don't. Column heights are variable. The project is being developed as a waterflood with horizontal and monobore producers and injectors. The initial phase of horizontal producers were completed with sand exclusion capability, consisting of multilayerd sintered screens. This has so far proved to be effective.
The Benchamas Waterflood project is comprised of eight stacked, compartmentalized, sandstone reservoirs. These sandstones are fluvial channels and are discontinuous. The waterflood is designed to maintain oil viscosity and gas cap location to maximize recovery. The economic impact of this waterflood is estimated to increase the recovery from an estimated 12-18% (primary) to 25-35% (secondary) of the OOIP.
During the design stage of the waterflood project, simulation indicated that some horizontal injector wells would be required to enable the required injection rates. Three horizontal injectors were therefore planned. The drilling, completion, and clean up of these wells presented the Benchamas Asset Team with a series of unique challenges.
Rock mechanics analysis was conducted in the decision process to address the need or lack of need for sand control. Results will be discussed.
Drilling fluid and flow back aspects of the wells were carefully examined in order to avoid some of the problems of horizontal injectors drilled in other parts of the world by the company. An extensive literature search revealed that the laboratory work required to adequately address the issues comprehensively had not been done. The company and the fluids vendor collaborated to conduct the laboratory tests that were required to determine the correct combination of fluids and clean up procedures necessary to successfully install these wells.
This paper will highlight the unique design challenges presented to the Asset Team, discuss the efforts that were undertaken to address these challenges and the results, and present the field results of the drilling, completion, clean up, and final injection results.
Integrated 3D Geological Data into Fluid Flow Model Improves Reservoir Management Plan: Serang Field Case Study
Authors: Sukerim Waryan , Vo D. T. , Stites Jim , Swanson Mark 
Published: December 2007

Abstract
This paper presents a field case study describing how 3-D geological data are used in reservoir simulation to improve performance forecast and help optimize the development of the Serang Field, East Kalimantan, Indonesia.
The Serang field consists of complex stacked fluvial and deltaic channel sands under a large gas cap and over a strong aquifer. Development of the field is a challenge with the reservoir heterogeneity nature of the sands and the dynamic movement of fluid flow. Reservoir management is even more difficult as the originally thick oil columns have now become thinner with long-term production as adding infill wells or planning workovers require more accuracy for target locations. The study demonstrates the workflow involved in integrating the 3D geological data for constructing a reservoir model for field management. The model constructed helps explain the reservoir fluid flow behavior, identify by-passed oil under reservoir heterogeneity, plan for infill locations and workovers and long-term development strategy of the field. It shows the key benefits include a faster work process of building a reliable model that accounts for crucial heterogeneity, flexibility in varying reservoir properties with new data, and quicker history matching of the production data. These allow for quick turn-around to evaluate multiple development plans while improving production forecast.
The paper also discusses the practical and operational use of the model results in planning, implementing and operating wells for optimizing oil and gas recoveries.
New Technique Prevents Proppant Flowback and Improves Fracture Conductivities
Authors: Di Lullo Gino , Rae Phil 
Published: December 2007

Abstract
Flowback of fracturing proppant during production is a common problem. The consequences of this can be extremely serious. Loss of fracture conductivity can occur due to reduced width, which can be further compounded by partial plugging of the pack by proppant fines. The latter are produced by non-uniform loading on the proppant with resultant failure and crushing. The produced solids can wreak havoc with both downhole and surface equipment, eroding chokes and nipples, plugging flow lines and filling separators. In the case of subsea wells, the problems are even greater and can compromise well security. Since the 1980&apos;s, the standard solution applied for prevention of proppant flow back has been the use of curable resin coated proppant. While this approach has met with some success, it is far from perfect. The use of RCP&apos;s can cause fluid compatibility problems and can interfere with well clean up. Such problems have prompted resin manufacturers to modify their products and have also opened the door for the introduction of new technologies. Newer developments have included the use of small fibres to try to bind the proppant pack together or heat-sensitive plastic film to partially encapsulate clusters of proppant. These materials have reportedly been used with some success but concerns have been raised with regard to their effect on fracture conductivity, amongst other things.
This paper describes the current methods in use and presents a new system that actually enhances fracture conductivity and minimises embedment and width-loss, while simultaneously helping prevent proppant back-production.
Coaly Sandstones: Reservoir Evaluation Problems and Solutions
Authors: Souvick Saha , Corbin Steve 
Published: December 2007

Abstract
In fluvio-deltaic sediments of East Kalimantan, Indonesia, coal commonly occurs and poses serious problems in reservoir evaluations. Thick coal seams can easily be identified, but it is often difficult to identify and quantify coal within sandstones using the conventional well logs. This can lead to inaccurate computation of reservoir parameters such as porosity, permeability and water saturation. In this paper, it is shown how petrophysical interpretation can identify these coals and improve decision making.
In order to understand the "coaly" response on well logs, a number of core slabs were studied. It was found that the coal within the sandstones mostly occurs as thin layers interbedded with sands, not "dispersed" as often thought.Previous petrophysical analyses were reviewed where coals were not interpreted properly and resulted in over and under-estimation of coals. The new petrophysical model (ElanPlus) is based on local knowledge and extensive core data, and overcomes earlier problems. Also, the application of new logging technology (Combinable Magnetic Resonance CMR) validated the new petrophysical model and a better insight was gained. Uncertainty in quantification of coals under unfavorable situations such as, hole wash out and lack of log resolution, is now better understood.
The new petrophysical interpretation accurately quantifies coals from the conventional well logs and addresses the long standing problem in East Kalimantan sandstones. Accurate reservoir parameters can be computed and better decisions on completions can be made.
Effective Slimhole Cementing in a Challenging Environment - A Gulf of Thailand Case History
Authors: Gilmore Todd , Harrison James , Pathanakitchakarnjaroen Duantem , Chanpen Chakrit 
Published: December 2007

Abstract
The successful development of a light weight slurry system for cementing long intervals at high temperatures in three dimensional multiple stacked gas zone wells, has been achieved in the Gulf of Thailand. The cementing system has been developed to successfully complete progressively more difficult wells, starting with conventional large bore wells and tubing plus packer completions, and later down-sizing into single monobore wells whereby the tubing is cemented in place. The problems associated with the down-sizing of the wells are further increased by more challenging well paths and higher temperature fields. Many problems and risks were overcome to complete this task successfully. These changes have posed new challenges in primary cementing.
Like the well size, the slurry system has also undergone a refinement and improvement process. The local industry has gone from dry blended slurry systems to all-liquid additive slurry systems saving considerable dollars, whilst realizing large gains in slurry flexibility, ease of mixing and improved logistics. Whilst developing and realizing these gains, the system has been refined and successfully applied to smaller, hotter and more difficult wells.
This paper presents the concerns associated with cementing these challenging wells where remedial cementing has been effectively eliminated. The processes related to this success, evaluation methods and field results will be discussed.
Comparing Exploitation and Transportation Technologies for Monetisation of Offshore Stranded Gas
Authors: Chang Seungyong 
Published: December 2007

Abstract
Natural gas is one of the important energy resources and the worldwide consumption is rapidly increasing. To satisfy such a demand of the natural gas, a number of gas fields are under development in hostile conditions such as deep seas and arctic areas. However, due to the status of current technologies and economic situations, many gas fields in offshore are stranded. The estimated stranded gas reserves are above 4,500 TCF in offshore areas. The proven technology options available to the offshore for the natural gas exploitation and transportation are extremely limited. Currently, the most popular methods of bringing the natural gas to market from distant locations are LNG (Liquefied Natural Gas) and PNG (Pipelined Natural Gas) technologies. However, these technologies require expensive capital cost for infrastructure constructions and huge proved gas reserves. Thus, in many situations, they are not available for the stranded gas exploitation and transportation. There exist alternative technological options to LNG and PNG technologies that can be considered for exploiting and transporting the stranded gas in offshore. They are CNG (Compressed Natural Gas), NGH (Natural Gas Hydrate), GTL (Gas to Liquid), and GTW (Gas to Wire). In this paper, the available technologies of CNG, NGH, GTL, and GTW have been reviewed and compared to LNG and PNG technologies to derive the most economical one in selected regions such as Mediterranean, Caribbean, Arabian Seas, and Sakhalin Island.
Experimental Investigation of Critical Flow Condensate Saturation
Authors: Guo Ping , Yang Jinhai , Li Shilun , Sun Liangtian , Jiang Tongwen 
Published: December 2007

Abstract
When gas condensate reservoirs are developed by pressure depletion, retrograde condensation occurs at pressure below the dew point of the condensate gas reservoir. The minimum saturation required for the flow of condensate in reservoir rocks is so-called critical flow condensate saturation (CFCS). We often want to know how much the CFCS is, about this, some study indicates the CFCS is 30-50%. Yet, field experience indicates the CFCS at much lower saturation of around 10%, particularly in the presence of connate water. Although this may be ignored in laboratory studies, it could significantly contribute to recovery at field scale.
An experimental equipment by ultrasonic has been established in order to directly determine the CFCS in core at high pressure fluid system. At first, we verify the way by applying different kinds of porous media (no media, filling media and synthetic media) and test the saturated vapor pressure of CO2 in them, then we use two real gas condensate and two synthetic cores (one: porosity 37.1%, permeability 1.44 μm2, and another: porosity 38.6%, permeability 1.73 μm2) to determine the CFCS, we demarcate the connection between condensate saturation and ultrasonic signal and get the CFCS which one is 15%, another is 18%.
A New Method for Computing Pseudoskin Factor for a Partially-Penetrating Well
Authors: Lee K. S. 
Published: December 2007

Abstract
An accurate knowledge of pseudoskin is important to quantify an additional pressure loss due to partial penetration or restricted entry. Though several procedures for computing the pseudoskin factor have been reported in the literature, they are either insufficiently accurate for geometrically-complicated reservoir systems or require the solution of a fully-transient diffusivity equation. This study aims to present a new method for estimating the pseudoskin factor of a partially-completed well. It has been designed to overcome a limited applicability of previous methods in geometrical or computational aspects. The method is derived from applying the equation for the pseudosteady-state flow of a slightly compressible fluid and accommodates one or more openings in a single or multiplayer reservoir where a crossflow occurs between reservoir layers. The solution of a pseudosteady-state equation describes the pressure response of a closed radial system during a boundary-dominated flow period. A pressure drawdown of any reservoir system, which can be easily evaluated from the solution, is compared against the analytical solution of a fully-penetrated system. The pseudoskin factor is, then, determined from the difference between the two sets of results.
Comparisons with previously published results are presented graphically. The reservoir types include various cases of homogeneous and multilayered systems with contrasting reservoir properties. It is shown that a highly accurate estimate of pseudoskin factor can be achieved regardless of the complexity of a reservoir system including the location of open intervals or number of layers. With minimum assumptions on the reservoir geometry, a greatly improved computational efficiency of pseudosteady-state approach permits the engineer to account easily for the effects of partial penetration on the productivity of a partially-penetrating well.