bluuebunny/crossref_metadata_2025 huggingface dataset:
Investigating anisotropy in shear strength of clayey soils
Authors: Attom M. F. , Al-Akhras N. M.
Published: October 2008

This study investigates the anisotropic behaviour of the shear strength of overconsolidated clayey soils. The results of the study will help engineers and scientists to predict the lateral shear strength of clayey soils from the ordinary vertical shear strength. The main objective of this paper is to investigate experimentally the effect of anisotropy on the shear strength properties of clayey soil. Fifteen types of clayey soil were obtained from various locations in the Irbid area, Jordan, and from different depths. Three undisturbed samples were obtained from each location at three different inclinations (horizontal, vertical, and inclined at 45° to the vertical). Unconfined compression tests were conducted on all soil samples. It was found that the unconfined compressive strength values were greater in the vertical direction than in the inclined and horizontal directions, and increased as the overconsolidated ratio increased. It was also noticed that the failure strain in the horizontal samples was smaller than in the vertical samples. The anisotropic behaviour of clayey soils almost disappeared at greater depth for both unconfined compressive strength and failure stain.
Long-term and acute effects of zinc contamination of a stream on fish mortality and physiology
Authors: Giardina Andrea , Larson Sandra F. , Wisner Brian , Wheeler John , Chao Matthew
Published: October 2008

A section of the Upper Enoree River in South Carolina, USA, was contaminated with chemical waste in 1985, and high concentrations of zinc persist decades later. In this study, we examined the zinc concentrations in the water, the accumulation of zinc in a variety of fish tissues, the effects of the contaminated water on fish sperm motility in vitro, and the mortality rates of introduced fish. Zinc concentrations in the water samples collected from six sites decreased as distance from the spill site increased, ranging from 7.3 to 0.34 mg/L (p < 0.001). The zinc concentrations of tissues from native fish were highest in liver (mean across sites of 110 ppm/g tissue) and gills (77.4 ppm/g tissue), followed by gonads (30.7 ppm/g tissue) and muscle (6.9 ppm/g tissue) (p < 0.001). The duration of fast motility of Salmo trutta sperm was significantly diminished in sperm activated in samples from the contaminated stream compared with the control stream (p < 0.05). To further evaluate the ability of fish to survive at the sites with different zinc concentrations, groups of Gambusia holbrooki were placed in traps at a reference site (uncontaminated local tributary), and three sites along the contaminated stream. Rapid mortality was observed in the two sites closest to the spill, including one site in which native fish had been found. The introduced G. holbrooki expressed higher zinc concentration in gills than gonads or muscle (p < 0.001), and water zinc concentration significantly affected fish mortality (p < 0.001). The results from these experiments indicate that zinc contamination of streams can have sublethal effects on populations and physiology of fish that are able to survive in the contaminated water.
Uptake and elimination of hydrophobic organic contaminants in estuarine copepods: An experimental study
Authors: Cailleaud Kévin , Budzinski Hélène , Menach Karyn Le , Souissi Sami , Forget-Leray Joëlle
Published: October 2008

Polycyclic aromatic hydrocarbons (PAHs) are considered to be rapidly biotransformed by organisms, whereas poly-chlorinated biphenyls (PCBs) are strongly bioaccumulated. In the present study, the estuarine copepod Eurytemora affinis was exposed in a continuous flow-through system to dissolved PAH (500 ng/L) and PCB (300 ng/L) mixtures for 86 h, whereas control groups were placed in a continuous flow-through system with clean water. Both PCB and PAH body residues were measured and compared in exposed and in nonexposed copepods to assess the uptake and the elimination of these two contaminant classes in this copepod species. After the exposure, exposed copepods exhibited concentration factors, based on a dry-weight basis, of 25, 750, and 1,200, respectively, for total PCBs and PAHs. The lower concentrations of PAHs in the nonexposed versus exposed copepods in contrast to small differences for PCBs suggest a higher rate of metabolism of PAHs compared with PCBs and could explain the differences observed in the accumulation. Furthermore, uptake as well as elimination of both PCBs and PAHs were compound selective in E. affinis. Therefore, higher-molecular-weight PCBs and PAHs were preferentially accumulated, while lower-molecular-weight compounds were preferentially eliminated. These results suggest the importance of copepods in the biogeochemical cycles of hydrophobic organic contaminants in estuarine ecosystems.
Feather growth influences blood mercury level of young songbirds
Authors: Condon Anne M. , Cristol Daniel A.
Published: October 2008

Dynamics of mercury in feathers and blood of free-living songbirds is poorly understood. Nestling eastern bluebirds (Sialia sialis) living along the mercury-contaminated South River (Virginia, USA) had blood mercury levels an order of magnitude lower than their parents (nestling: 0.09 ± 0.06 mg/kg [mean ± standard deviation], n = 156; adult: 1.21 ± 0.57 mg/kg, n = 86). To test whether this low blood mercury was the result of mercury sequestration in rapidly growing feathers, we repeatedly sampled free-living juveniles throughout the period of feather growth and molt. Mean blood mercury concentrations increased to 0.52 ± 0.36 mg/kg (n = 44) after the completion of feather growth. Some individuals had reached adult blood mercury levels within three months of leaving the nest, but levels dropped to 0.20 ± 0.09 mg/kg (n = 11) once the autumn molt had begun. Most studies of mercury contamination in juvenile birds have focused on recently hatched young with thousands of rapidly growing feathers. However, the highest risk period for mercury intoxication in young birds may be during the vulnerable period after fledging, when feathers no longer serve as a buffer against dietary mercury. We found that nestling blood mercury levels were not indicative of the extent of contamination because a large portion of the ingested mercury ended up in feathers. The present study demonstrates unequivocally that in songbirds blood mercury level is influenced strongly by the growth and molt of feathers.
Acoustic Leak Monitoring on Subsea Valves
Authors: Instanes Geir , Pedersen Audun
Published: October 2008

Acoustic leak monitors in mechanical contact with components of special interest have clear advantages over many alternatives, in particular for continuous monitoring over time or during specific operations. Non-invasiveness and repeatability are among the most important benefits of this technology. In connection with a delivery of self-contained, battery operated subsea leak monitors, the technology was demonstrated in a laboratory environment. A 20″ subsea valve was fitted with acoustic leak monitors, pressure sensors and a mass flow meter. Artificial damages were made to the valve in three incremental steps. One port was pressurized with nitrogen, and the resulting leakage flow was detected and quantified. Detection thresholds as low as 1 SCM/h were observed in the demonstration. Higher thresholds are however predicted for most field situations.
New High-Temperature Optical Fiber Technology Successfully Provides Continuous DTS Data under Severe SAGD Conditions
Authors: Kaura Jiten , Sierra Jose , Park Bob
Published: October 2008

The use of optical fibers in the oil and gas industry is becoming more viable for several applications, particularly in permanent reservoir monitoring, such as distributed temperature sensing (DTS) and optical pressure transducers. However, poor long-term performance of fibers, especially at elevated temperatures, is still an issue yet to be fully resolved. This problem is critically important in steam assisted gravity drainage (SAGD) applications, where wells operate in extreme conditions of high temperatures, often exceeding 250°C, as well as in high pressures within a hydrogen-rich environment. Optical fiber performance is seriously affected by many factors, including: Hydrogen ingressionThermal resistance of the materialsMechanical resistance of the fiber

Exposure of optical fibers to hydrogen changes the performance of the fibers through what is referred to in the industry as "hydrogen aging" or "hydrogen darkening." Hydrogen darkening is increased absorption or light loss due to various chemical species in the glass fiber resulting from the presence of hydrogen.
The Reservoir Suitability Studies of Nitrogen Foam Flooding in Shengli Oilfield
Authors: Liu Renjing , Liu Huiqing , Li Xiusheng , Fan Zhicheng
Published: October 2008

Many previous researches have proved that foam can increase the sweep efficiency and control gas mobility, and thus increase oil recovery. However, research on the effects of reservoir conditions such as the permeability, reservoir heterogeneity, formation rhythm and the viscosity of prude oil remains incomplete. Therefore, it is significant to study the foam efficiency in different reservoir conditions for large scale application of foam flooding.

The foaming agent was evaluated in laboratory and flooding experiments were conducted upon two groups of long real formation cores from Shengli oilfield to study foam flooding efficiencies. The effects of core permeability and gas liquid ratio on foam resistance factor were discussed. And then operating parameters including gas liquid injection ratio, injection rate and foam injection time were optimized and the influence of reservoir heterogeneity, the viscosity of crude oil and formation rhythm on nitrogen foam flooding efficiency were investigated at length by means of numerical simulation in the light of Shengli specific reservoir conditions.

The results show that, nitrogen foam flooding has excellent blocking ability and the optimum ratio of gas to liquid is 1.5:1; and the optimum foam rate is0.2 pore volume; the best foam flooding time is when the water cut of production well is 85%~ 90%. Nitrogen foam flooding is more effective for heterogeneous formations rather than for homogeneous ones. Furthermore, the efficiency of the flooding system decreases with the increasing viscosity of crude oil and is better in regular rhythm formation than that in negative rhythm formation. Finally, some easy-to-use and practical charts are drawn to analyze the economic benefits of nitrogen foam flooding for the given reservoir.

The study results provide a set of reservoir criteria that can be used as guidelines to choose potential reservoir candidates for nitrogen foam flooding.
Moving from Vision to Reality – The State of Optimal Value Testing
Authors: Elshahawi Hani , Hite Robert H. , Hows Melton P.
Published: October 2008

Over the past few years, there has been a vision in Shell that Optimal Value Testing (OVT) would some day replace conventional drill stem tests for in-situ measurement of dynamic reservoir properties such as permeability and drainage volume. This vision is that OVT would be safer, less costly, and friendlier to the environment, but the key impediment to OVT was that the quality of the results might be inadequate for the difficult development decisions that we face.

Definitions of OVT may vary, but in Shell we define it as the testing method that yields fit-for-purpose results with the lowest cost and HSE impact. In more pragmatic terms, it is any pressure transient test in which live hydrocarbons are not produced directly to surface. Currently we have three types of well tests in our OVT toolbox – wireline formation testers, the closed system test with cleanup and repeat surges, and injectivity testing. We have recent examples of closed system tests and wireline formation tests that show we can get comparable data quality to a conventional DST. Injection testing, aimed at determining drainage volume, is less mature and we have yet to execute an injection test. However, there has been considerable design work that makes us believe, given the recent experience with closed chamber systems, that that technology can also be successful.

This paper describes the strengths, weaknesses, and opportunities of each OVT type. We present several examples of design, execution, and analysis of these tests. The technology is immature, and there are more issues to resolve than with a conventional drill stem testing. However, by drawing on our increasing breadth of experience, future value of information decisions we take about doing in-situ dynamic measurements will more often include the cheaper, safer, and more environmentally friendly OVT.
Steam Flooding Field Fault Reactivation Maximum Reservoir Pressure Prediction Using Deterministic and Probabilistic Approaches
Authors: Yi X.
Published: October 2008

Fault reactivation induced by excessive reservoir steam pressure in heavy oil fields is suspected as one of the possible perpetrators that caused steam eruption to the surface. This can lead to significant financial losses related to environment cleanup and curtailed oil production. A traditional approach to fault reactivation prediction provides a deterministic critical reservoir pressure without proper regard to the uncertainties in the model input parameters and the predicted results. A probability distribution of the fault reactivation maximum reservoir pressure provides a better means to calculate a risk weighted Expected Net Present Value for management to make better decisions on steam flooding and to anticipate potential consequences.

In this study, a geomechanical model was established for the Batang Field, Central Sumatra, Indonesia. Using the geomechanical model, first, a fault seal analysis was performed and indicated that all faults were sealed in sands under initial stress and pore pressure conditions. Second, fault reactivation reservoir pressures for major faults in the field were predicted assuming a frictional sliding frictional coefficient of 0.5, which was derived using frictional faulting theory by a geomechanics services provider for the nearby Duri Field. Two scenarios were run in this case. One assumed a stress path coefficient of zero for horizontal stresses (decoupled); the other assumed a stress path coefficient of 0.4 (coupled). It was found that the coupling of stress and reservoir pressure provides a less conservative value of maximum reservoir pressure. Lastly, Monte Carlo simulations were run to consider the uncertainties of frictional sliding coefficient, and especially the stress path coefficient among the input parameters. It was found that the results from Monte Carlo simulations and deterministic approach were largely consistent but the resulting probability distribution from the Monte Carlo simulation approach provides significantly more information.
Determination of Gas Well Deliverability in Volcanic Gas Reservoir Using Transient Testing Data
Authors: Qinglong Xu , Rui Shao , Shiquan Yu , Baizhou Fu
Published: October 2008

Quite a few large-scale volcanic gas reservoirs have been discovered in deep zone in Songliao Basin of North-East China in recent years. The consequent issue is how to produce this kind of gas reservoir effectively. The interpretive principle and method of gas well multi-point open flow potential test demands that testing technology meet sustained measuring condition, while during actual productivity testing, productivity and bottomhole pressure is not steady yet affected by various reasons, these testing multi-point open flow potential test data can not use conventional productvity analysis method to calculate, especially Daqing deep volcanic gas reservoir is low permeability gas reservoir, productvity testing needs a long steady time, so testing cost is very high. The article is aimed at unsteady testing productivity or bottomhole pressure condition, deduction a new evaluation of gas well productvity equation in theory, base on unsteady seepage theory, using pressure superposition principle deduce variable production rate unsteady seepage gas well binomial productvity equation expressed with pressure square, present relevant analysis method of gas well productivity. This method can save a lot of testing time, improve data utilization factor, provide us a credible method to establish gas well productivity of low permeability gas field.
Gas Monetization for Sustainable Development, The Trinidad and Tobago Experience
Authors: Baksh Timmy
Published: October 2008

Developing new gas markets is a long-term undertaking. It is this thinking that has driven the actions of the Government of Trinidad and Tobago to deliberately pursue a strategy of gas market development. The success story of Trinidad and Tobago's ability to monetize it's hydrocarbon resources is unique and Trinidad and Tobago is one of a few countries that has developed a successful formula to monetize gas in a comprehensive manner, by developing broad-based domestic consumptive industries and also a direct export market in LNG.

The global energy market is very dynamic and the demand for energy, when considering security of supply, safety and the environment, is constantly shifting. Trinidad and Tobago, through aggressive policy initiatives and institutional strengthening of the regulatory agency, has been able to successfully adapt to this volatile global market. This paper will examine the various policies and discuss the restructuring of the regulatory agency within Trinidad and Tobago.

Trinidad and Tobago has built a large and diversified market for natural gas and is one of the most diversified gas-based petrochemicals centres in the Americas. This successful formula for monetization and sustainability has become known as the Trinidad and Tobago Model. This paper will seek to elaborate on this Model and examine the various development strategies pursued, which has successfully lead sustainable and diversified industrialization within the energy sector of the country.

This paper will also focus on the strategic geographical location of Trinidad and Tobago and how the Country has and is continuing to foster regional and international energy and gas-integration ventures. Trinidad and Tobago is well endowed with hydrocarbon reserves and has positioned itself as one of the emerging markets in the Western Hemisphere. This paper will provide an insight on Trinidad and Tobago position as a key player in the global energy market.
Appropriate Assessment of Gas-Liquid Slippage – A Critical Step from a Good Production Logging Survey to a Successful Workover for Gas Wells
Authors: Ouyang Liang-Biao , Suthichoti Polpipat
Published: October 2008

Production logging (PLT) has been routinely applied in oil and gas industry to estimate phase production profile, determine oil/gas/water producing layers, and detect major fluid entry or exit. Through successful PLT surveys and appropriate interpretation, it may also be possible to identify thief zones and high perm channels, locate injected fluid breakthrough, monitor fluid front movements, detect crossflow and fluid migration, assist in reservoir simulation studies, etc.

Subsequent workover operation following a PLT run is frequently performed aiming at reducing water production while maintaining/increasing oil and/or gas production. Unfortunately, in practice, mixing results have been obtained through workover operations designed based on PLTs, due to poor logging procedure, unreasonable PL tool selection, poorly executed surveys, inappropriate interpretation, etc.

In the presence of multiphase flow in a well, interpretation of production logs becomes critical for achieving successful estimate of major fluid entries and thus successful workover operation. Appropriate interpretation of production logs relies heavily on the selection of a reasonable multiphase flow model to correctly estimate gas-liquid slippage and capture complex multiphase flow features.

In this paper, the major flow characteristics of multiphase flow in a wellbore will first be described. Different correlations/models to describe multiphase flow and calculate slippage will then be introduced; the pros and cons of each correlation/model will be highlighted. The impacts of multiphase flow model selection and gas-liquid slippage assessment on the interpretation results of production logs will be investigated.

Field case histories will be described to illustrate the critical roles played by reasonable gas-liquid slippage assessment in production log interpretation. PLT interpretation based on different slippage assessments will be shown and compared with actual workover results. Guidelines for appropriate gas-liquid slippage assessment for production log interpretation will be provided and key lessons learned shared.
Reservoir Fluid Evaluation from Real Time Pressure Gradient Analysis: Discussions on Principles, Workflow, and Applications
Authors: Zhou L. , Mardambek J.
Published: October 2008

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

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

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

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

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

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

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

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

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

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

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

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

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.
Multiwell Injectivity for CO2 Storage
Authors: Zakrisson Johan , Edman Ingrid , Cinar Yildiray
Published: October 2008

A multiwell injectivity model is necessary to assess CO2 injection potential in subsurface formations. This necessity becomes almost ineluctable when CO2 is injected into low-permeability formations, which requires multiple injection wells in order to compensate a minimum injection rate for commercial projects. The pressure interference between the injection wells located in the same reservoir causes significant injection losses.

This paper examines well interference when injecting fluids with more than a single injector in a porous medium. Two cases of multiwell injection are studied; water injection and gas injection in a water filled reservoir. In both cases the aim is to examine the degree of well interference caused by the number of wells, formation permeability, well spacing, and total injection rate. A steady-state analytical model obtained using the superposition principle is used for the flow of a slightly compressible fluid of constant viscosity and compressibility in a rectangular homogeneous reservoir of uniform thickness, porosity, and permeability. The wells are represented by fully penetrating vertical line sources with a constant well spacing in a regular pattern. The model is used to calculate the required number of wells for given reservoir parameters and total injection rate. The results are compared with those obtained using single-well and multiwell numerical models.

Comparisons show that there is a good match between the multiwell analytical and numerical models for permeabilities higher than 10 mD. It is found that the single-well analytical model underestimates the well numbers compared to the multiwell analytical and numerical models for this range of permeabilities whereas for permeabilities lower than 1 mD it has a good agreement with the numerical model. It is argued that the reason for this should be well interference because the flow in low permeability media is relatively slow, causing less interference between the wells.
Gorgon Project: Subsurface Evaluation of Carbon Dioxide Dsposal under Barrow Island
Authors: Flett Matthew , Beacher Graeme , Brantjes Jeroen , Burt Aaron , Dauth Chris , Koelmeyer Fiona , Lawrence Robert , Leigh Seb , McKenna Jason , Gurton Randal , Robinson IV William F. , Tankersley Terrell
Published: October 2008

The Gorgon Project is a major LNG development to be based in Northwest Australia. Gas will be produced from several offshore gas fields located in the Greater Gorgon Area with processing facilities to be located on Barrow Island. The reservoir fluids of several of the fields contain carbon dioxide (CO2) which will be extracted from the produced gases prior to liquefaction into LNG. The Gorgon Joint Venture participants have proposed to geologically dispose of the produced reservoir CO2 from the gas processed at the Barrow Island LNG plant.

The CO2 injection project was extensively documented and subjected to public comment as part of the Gorgon Project Environmental Impact Assessment Process. Following this process the WA Environmental Protection Authority found that the environmental risks associated with the CO2 injection project were acceptable and recommended that CO2 injection must proceed as an integral component of the Gorgon Project.

The target formation for geological disposal of this carbon dioxide is the Dupuy Formation, a Jurassic saline reservoir, deep beneath Barrow Island. The evaluation of the Dupuy Formation for the disposal of carbon dioxide was focused on characterising the reservoir and narrowing subsurface uncertainties not addressed by legacy oil exploration and development. Data acquisition was targeted to reduce major subsurface uncertainties including a seismic pilot to assess acquisition methods (including 4-D seismic) and an extensively evaluated appraisal well. Robust geological description, hydrodynamic, static and dynamic reservoir models have been used to gauge the impact of CO2 injection on development decisions. Key drivers for this development have been maximising per well injection of CO2 and ensuring containment of CO2 within the reservoir. Through effective subsurface and economic evaluation, a phased and flexible development plan for CO2 disposal has been developed to meet these objectives.