bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Fluid Evaluation from Real Time Pressure Gradient Analysis: Discussions on Principles, Workflow, and Applications
Authors: Zhou L. , Mardambek J. 
Published: October 2008

Abstract
Modern formation pressure testing while drilling (FPWD) tools provide accurate formation pressure measurements, even under very challenging drilling and formation testing conditions. Pressure data from logging while drilling (LWD) tools are primarily used for drilling safety related pore pressure profiling, mud weight optimization and ECD controls. Its full potential in formation and reservoir evaluation has yet to be further explored.
Pressure gradient analysis is a particularly cost-effective solution for preliminary reservoir fluid evaluations while drilling or shortly after the well is drilled. Integrated with other LWD and surface logging data, pressure gradient analysis is able to provide valuable insight for planning subsequent fluid sampling, well completion and reservoir development programs which require accurate assessments of fluid types, fluid contacts, reservoir compartmentalization, and connectivity.
Based on data and experience from recent worldwide FPWD and gradient jobs, we present a recommended best practice workflow for pressure gradient analysis using real time pressure testing data. The main procedures of the workflow consist of pre-job preparation, real time wellsite execution, quality control, statistics and error analysis, proper graphic presentation, data integration and interpretation. Special effort is made to identify fluid types, contacts, vertical fluid variation and reservoir barriers from pressure gradient analysis. It is found that the integration of pressure data with openhole logs and surface mud gas logging is particularly effective in reducing uncertainties in the interpretation. Possible factors responsible for departure from linear pressure gradient trend lines are discussed together with the limitations of gradient analysis.
Quick reservoir evaluation in terms of fluid types, oil water contact (OWC), oil gas contact (OGC) and flow barriers can be obtained independently with the use of pressure gradient analysis from FPWD data. More reliable results are achieved by the integration of pressure measurement data with the openhole log interpretation, surface logging and offset well information collected in the pre-well planning stage as well as while the well is being drilled.
Scaling and Sensitivity Analysis of Gas-Oil Gravity Drainage EOR
Authors: Jadhawar P. S. , Sarma H. K. 
Published: October 2008

Abstract
Gas injection is one of the key enhanced oil recovery (EOR) methods. Significant volumes of the residual oil, remaining after earlier EOR methods, has been reported to be recovered through the gravity drainage mechanism, following the crestal gas injection in the horizontal, dipping or reef type oil reservoirs. The rate of oil recovery is controlled by the viscous/capillary/gravity forces, the rate of gas injection and oil production, the difference of oil and gas density, the oil relative permeability, the oil viscosity and number of other operational parameters. Risk analysis of these parameters helps to identify their relative dominance during gas-oil gravity drainage process. The interactions between various process controlling parameters is studied through development of scaling groups that govern the displacement process. Functional relationships between those scaling groups and their effect on the overall performance of immiscible gas-driven gravity drainage EOR are investigated in this study. This enables an estimation of fractional oil recovery for the combinations of scaling groups. The results of numerical sensitivity analysis through the reservoir simulations are presented to map the effective combinations of the dimensionless scaling groups for gas-oil gravity drainage EOR method.
Corrosion and Hydrate Control in Wet Sour Gas Transmission Systems
Authors: Moloney J. J. , Mok W. Y. , Gamble C. G. 
Published: October 2008

Abstract
Generally, the most economical material for construction in oil and gas pipeline systems is carbon steel. Besides the safety and environmental issues, downtime caused by corrosion related failures and hydrate-induced blockages in pipelines can be costly to the operator. Asset integrity and flow assurance are, therefore, recognised to be critical issues in oil and gas production and transportation. Chemical inhibitors to protect pipelines from metal degradation and hydrate blockages are commonly utilised but compatible corrosion inhibitor (CI) and kinetic hydrate inhibitor (KHI) combinations are often difficult to formulate for sour gas applications. It is often found that either the KHI has an adverse affect on the CI function or vice versa. Before field deployment, extensive inhibitor testing and evaluation is conducted to ensure that the most appropriate products are selected. This paper presents data from a laboratory programme which was instigated to develop and assess new corrosion inhibitor formulations. Performance was evaluated in terms of the corrosion inhibition of the CI and its KHI compatibility and performance in supplementary secondary property tests under simulated sour gas pipeline operating conditions. From this work two CI/KHI combinations exhibiting excellent compatibility in terms of corrosion inhibition performance (both general corrosion inhibition as well as, more importantly, pitting corrosion inhibition), hydrate inhibition performance and high temperature injection performance have been developed.
JZ20-2 Offshore Gas-Field Group: Performance Adjustment and Progressive Development
Authors: Peng Chen 
Published: October 2008

Abstract
Since its production, JZ20-2 Gas Condensate Field was harassed by the problem of liquid coning. To solve this problem, step-rate testing was taken in all wells annually. And reasonable production rate was allocated to each well according to the testing results and well's productivity. This method restrained the oil coning successfully for several years.
However, along with the decreasing of the gas field pressure and the gas-oil ratio, more and more wells were affected by the bottom oil coning. So, the development strategy was changed to exploit progressively the nearby small gas-bearing structure to reduce the gas production of JZ20-2 Gas Condensate Field. From then on, the gas reservoir of JZ9-3 Oil-gas Field, JZ20-2N Block and JZ21-1 Gas Field was exploited gradually. This strategy made up the gas shortage of JZ20-2 Gas Field and utilized the gas resource of nearby area sufficiently.
This paper reviews the production history of JZ20-2 Gas Condensate Field. And it described problems met in production and analyzed the corresponding adjustment methods. From these adjustments, successful experiences and lessons on gas field development was summarized.
Reducing Time to First Gas: Lessons Learned in Expediting and Informing International Investment Chain Decisions
Authors: Resley Deborah D. 
Published: October 2008

Abstract
Long-lead and risk issues in global gas developments are primary threats to value and project efficiency. Appropriate decision focus and a value-chain context provide practical ways to shorten the time to first gas as well as illuminate options to add value. Decision-based uncertainty management skills become paramount for success.
The monetization of gas, particularly in liquefied natural gas (LNG) projects, requires large capital investment in most if not all links of the gas value chain from production to end use. Companies which invest in a single component of the value chain, such as non-integrated gas producers, must understand the value of and risks inherent in every link in the chain, as gas will be priced in relation to its final point of sale. Final sale price as well as the effects of processing and capacity limitations ripple their way upstream to alter the timing, demand, and viability of the upstream investment.
Investment decisions and the associated risks inherent in LNG projects are legion. Although operating companies can mitigate some of the risks through experience and partnering, many above-ground factors (uncertainties) are outside of investors' control, including market evolution, regulatory changes in either the producers' or the end users' markets, technological advances/failures, as well as run-ups in capital costs of raw materials such as steel. Because of these and other uncertainties, to assess or plan the monetization of gas using an advocacy-led set of assumptions is not optimal. A clear, unbiased and integrated decision management process both optimizes the investment and shortens the time to first gas.
Miscible CO2 Injection: Sensitivity to Fluid Properties
Authors: Nasir F. M. , Amiruddin N. A. 
Published: October 2008

Abstract
Miscible gas injection has been identified to be the most amenable enhanced oil recovery (EOR) process for Malaysian oil fields. Due to economic and availability reason, carbon dioxide (CO2) is the most potential source of gas for this process. In order to predict the performance of these fields undergoing miscible flooding using a reservoir simulation, there is a need to identify parameters that have significant effect on the results. Sensitivity study is usually conducted to evaluate the effect of varying parameters on the reservoir performance. This paper presents the results of the study using numerical simulation, with the emphasis on fluid properties since these data are usually obtained from laboratory measurements or correlations, which generally subjected to great uncertainties. Therefore, it is the main objective of this work to determine the fluid properties that have major impact on the oil recovery from miscible CO2 injection. Using an extended black oil simulator, the effect of varying oil and injected gas density, viscosity and formation volume factor, on the flood performance is assessed. The effect is quantified using an index called normalized root-mean-square deviation and a fractional change index. From the results of the simulation, the model is found to be most sensitive to fluid formation volume factors, followed by their densities and least sensitive to the fluid's viscosities. Thus, it is recommended that these data must be properly selected and analyzed beforehand in order to minimize their uncertainty prior to any simulation works.
Optimised Field Development Planning in a Complex Geological and PSC Environment
Authors: Boardman D. , Habib S. , Rumbos M. , Vasantharajan S. 
Published: October 2008

Abstract
The paper describes an optimisation methodology used to aid development planning for the A-18 block in the Malaysia Thailand Joint Development Area (MTJDA). Development of this block is complicated by the large areal extent, gas residing in up to fifteen different major reservoir sequences, large depth range with the deeper sequences being HPHT intervals, and CO2 contents varying from 1 to 60%. An optimised field development plan has to maximise economic value from a volume based gas sales agreement which generates a heating value based revenue stream linked to CO2 level, and prioritises condensate production. The interplay between gas and liquids considerations and a myriad of potential platform and development drilling options within a PSC environment makes the selection of an optimum development scenario difficult.
The paper describes how a decision framework was used to maximise the economic value of the asset. This custom built software automatically generates possible development scenarios, and then uses branch-and-bound and outer approximation solution techniques to analyze and efficiently "prune" the scenario tree to eliminate sub-optimal candidates. The results illustrate the effectiveness of applying optimisation technology to this complex asset, as development plans can be quickly and robustly constructed for different GIIP and recovery scenarios and for different objectives such as maximising sales gas volume or NPV.
Pushing the Limits: Improving Drilling Performance of High Temperature Gas Wells in Thar Desert in Sindh, Pakistan
Authors: Qureshi Ali , Ali Muhammad , Preining Peter 
Published: October 2008

Abstract
Improving drilling performance leading to reduction in Well drilling time and the associated costs, without compromising the deliverability of the Well, is the primary objective of drilling engineering. Some of the major challenges faced by Drilling Engineers include damage to the pay zone while drilling the reservoir section, lost circulation problems, drilling of hard and abrasive formations and more. With recent advances in drilling-related technologies, these issues have been addressed and tremendous time and cost benefits have been realized.
OMV has been drilling high temperature vertical gas wells up to 4000m in Sindh, Pakistan. For drilling the reservoir section, OMV Pakistan pioneered the use of high temperature Formate Brine systems. These are solids free, high temperature stable drilling fluid systems which incur minimal damage to the reservoir. Application of these has yielded excellent results in terms of drilling as well as reducing skin damage.
To combat lost circulation, OMV Pakistan introduced and successfully implemented the concept of Advanced Engineering Fibers (AEF) mixed in mud to control the losses in fractured limestone formation. The AEF-mud pill soaks, or can be squeezed, into the formation and immediately creates a fiber-net barrier preventing further losses. The successful implementation of this technology is a landmark achievement in controlling mud losses.
Through optimized bit design and selection process, OMV Pakistan was able to realize its goal of ‘One Bit per Section’ drilling. Well Sawan-11 was drilled to a depth of 3415m with a milestone single bit run of 1758m at an average ROP of more than 25 m/hr. The bit was pulled ‘Green’ with minimal damage to cutters. This resulted in less drilling time and tremendous cost saving.
This paper presents accomplishments, experience, and lessons learned related to drilling in the Sindh area where the reduction of drilling time from nearly 3 months to around 3 weeks is an outstanding outcome of the "Pushing The Limits" concept.
Powered Rotary Steerable Systems Offer a Step Change in Drilling Performance
Authors: Al-Yami Hussain E. , Kubaisi Abdallah A. , Nawaz Khalid , Awan Amir , Verma Jaywant , Ganda Sukesh 
Published: October 2008

Abstract
Drilling horizontal gas wells at an average TVD of 12,500 ft in Saudi Arabia has always been very challenging owing to harsh drilling conditions. These wells are drilled in southern Ghawar field. Subject formations include bands of Lower and Middle Triassic and Upper Permian, composed of dolomite, shale, silt stone, and anhydrite formations. The main challenges in drilling these formations are slower penetration rates and difficulty in sliding with conventional motors in both the build and lateral sections.
This paper describes a step change in drilling performance using powered rotary steerable systems (PRSS) technology that led to record directional runs through difficult Khuff sections.
With the PRSS assembly, the company was able to drill both vertical and curve sections in one run, maximize ROP, and increase footage per bit run while meeting directional requirements. PRSS successfully kicked off from vertical and improved ROP up to 192% compared to conventional motor ROP in deep gas drilling. Significant improvements in ROP resulted in saving multiple bit trips in 12-in., 8 3/8-in., and 5 7/8-in. hole sections.
A New Approach to Estimate CBM Gas Content from Well Logs
Authors: Bhanja A. K. , Srivastava O. P. 
Published: October 2008

Abstract
Determination of the initial gas content in a coal section is the critical step in the evaluation of CBM resource. Gas content of coals is perceived to have a functional relationship with the relative abundance of two sole components namely organic and inorganic. The organic components remain fairly constant in a particular field, whereas the inorganic component may change considerably, both laterally and vertically within the field. Thus the log responses are logically expected to respond to the variation in inorganic components and offer a scope to effectively estimate the gas content of coals through log responses. However, the sole dependence on density log instead of using it in tandem with other logs like sonic, photoelectric absorption, gamma ray etc, which also respond to the variation in the inorganic components of the coal render the present in vogue methods less effective.
As a sequel in this proposed approach above mentioned logs have been used along with density log to generate a composite number C for each cored sample point. Then the depth wise plot of composite numbers C has been matched with the actual gas content data curve. Interestingly, it has been found that the signature of curve C overlays nicely with the core derived gas content curve with a constant shift (K). This shift appears to be unique and will vary from field to field depending upon the characteristics of coal. Estimation of gas content at a particular depth can be obtained by simply adding the K value with the value of C.
This methodology has been applied in two completely different coalfields namely Jharia (Bituminous) and Barmer-Sanchore (Lignite) of India and the results are consistently encouraging and show reasonably good accuracy. This technique offers a scope to be used in various types of field having different coal characteristics.
The Use of the Near-bit Vibration Sensor While Drilling Leads to Optimized Rotary-Steerable Drilling in Push- and Point-the-Bit Configurations
Authors: Sugiura Junichi 
Published: October 2008

Abstract
In an extended-reach and horizontal well drilling environment, stick-slip becomes increasingly problematic with smaller-diameter and longer drillstring. Surface detection of the bottom-hole assembly stick-slip and vibration becomes ever more difficult. A Real-time Stick-slip and Vibration Detection (RSVD) system was incorporated into a rotary-steerable system (RSS), to increase drilling efficiency in deep wells and to protect the RSS and the MWD/LWD tools from harmful vibrations. Bit/BHA instability often results in excessive vibration and stick-slip problems, which lead to BHA component failure, poor directional results and excessive wear/damage to bits.
This system is a unique near-bit vibration sensor integrated into the RSS, featuring detection of the three principal modes of drillstring vibration: torsional, lateral and axial. The sensor system sends the detected stick-slip severity to the surface in real time so that operators can change drilling parameters if harmful downhole conditions are detected. Additionally the real-time drilling data were remotely available to a multi-disciplinary drilling optimization team consisting of engineers and researchers.
This sensor system has been extensively tested and proved to be effective with the 8 ½-in.-hole-size RSS in various wells, including vertical and horizontal, both onshore and offshore. This paper reviews the harmful stick-slip and vibration conditions in smaller-hole-size wells and how the RSVD system improved penetration rate and prolonged the optimum performance of the drill bit, bottom-hole assembly (BHA), MWD/LWD, and RSS in various situations.
Through the integrated sensor and team approach, the ability to detect poor borehole conditions and/or BHA instability due to vibration allows RSS operators to take timely remedial action before downhole RSS failure occurs. As a result, the performance and survivability of the RSS has been remarkably improved.
Chemical Foamers for Gas Well Deliquification
Authors: Willis Martin J. , Horsup David I. , Nguyen Duy T. 
Published: October 2008

Abstract
There is a noticeable impact on a gas well's production rate when there is a build up of liquids downhole in the casing and the tubing of the well. The liquid may be in the form of formation water, condensed water or hydrocarbon condensate, but coupled with a fall in reservoir pressure the affect on production is the same. It causes the flow regime of the well to change, to an eventual point when the well ceases to produce. This is due to a hydrostatic lock, typically in the tubing, that the well pressure is unable to move.
To reduce the production decline and prevent premature well shut in chemical foamers can be used as a means of artificial lift. These are surfactant chemistries designed to modify physical properties of the liquids, such as surface tension, which aid unloading. The common chemistries used are discussed in this paper and a detailed explanation provided on how they are effective at deliquifying gas wells.
To develop this technology for commercial use it is important to have a process for evaluating performance. This begins in the laboratory using the unloading rig. This is a test method that provides information on the foam generated as well as indicate an unloading potential. Once a potential candidate has been identified in the lab then the process is undertaken to transfer the technology to the field. Identifying a suitable well to enable a field trial to be completed. Within the paper the test method is explained and the transfer process and results from the field presented.
History Matching of Field Production using Design of Experiments
Authors: Gupta R. , Collinson R. , Smith G. C. , Ryan S. , Louis J. 
Published: October 2008

Abstract
An important aspect of reserves estimates is to quantify the contribution of uncertainties in underlying parameters such as structure, Sand extent, Fault Seal, Aquifer support, etc. If field production history is available, it can be incorporated to generate reliable measures of uncertainties for these parameters and identify the most likely field models. History Matching (HM) can be solved successfully using the Design of Experiment (DOE) method to define modeled scenarios. In the past decade DOE methodology has been used to compute estimated reserves while minimizing the simulation effort. This paper describes its extension to History Matching.
The process of HM using DOE is a four stage process. The first step is to identify an uncertainty frame-work listing the uncertain parameters (X) and history matching parameters (Y). The second stage is to generate a design (the specified model combinations of the reservoir parameters) capable of estimating the effect and interactions of all parameters. Thirdly, the specified models are made and simulated and the response surface y(x) calculated, relating reservoir simulator input x and each output y. The last step is to predict the history matching parameter values for all possible model scenarios and measure goodness of history match for each model.
The History Match can be quantified by the D-Score, a measure of the difference between the realized and predicted value of the history matching parameter standardized across modeling error. The D-score based probabilistic measures are flexible and allow the user to incorporate prior information.
The above methodology for History Match will be presented for a field, which has over 11 years of oil production and 7 years of water-cut. We will demonstrate that History Matching using DOE is reliable, fast, efficient, and can quantify the probability of scenario occurrence.