bluuebunny/crossref_metadata_2025_split huggingface dataset:
Suitability of Horizontal, Inclined, and Vertical Wells on an Indian Offshore Platform Using Pressure Transient Analysis
Authors: Anand Abhijeet 
Published: October 2012

Abstract
The Indian offshore field under study has "LA" reservoir as one of the main producer. While the testing was carried out, nearly 20 wells were completed out of which 17 were on production, producing about 18,000 BOPD. "LA" reservoir is relatively clean and well developed in the crestal part of the reservoir. The average thickness of "LA" reservoir in the crestal part is 35-40m and increases upto 70m towards the flank. The Gas Oil Contact and Oil Water Contact are at 940m and 740m from MSL respectively. The IOIP and IGIP are of the order of 100.6 MMt and 2297 MMm3. In order to ascertain productivity of horizontal well, maximise oil recovery, prevent possible gas and water coning besides mastering of the technology, it was proposed to drill two horizontal wells.
This paper studies the Pressure Transient data of the Horizontal, Inclined and Vertical well of the same field. The interpretation of the horizontal well testing data was more complex due to development of shorter flow regimes. The data, however, is carefully analysed using the available software to determine several parameters including the average permeability and "k.h" product. The diagnostic derivative plots are used to determine the different flow regimes. Using the results, the permeability anisotropy and specific productivity was calculated for each well system. Replacement Ratio of horizontal to vertical/inclined well was determined using Newton's mid-pt numerical method and the cost analysis was done. Replacement Ratio and Cost ratio was combined for comparison of the three well systems.
Replacement Ratio was determined to be 2.25 which means 2.25 vertical wells may replace 1 horizontal well with same rate of production while Cost ratio for horizontal to vertical well was 2.40. On combining the two, it implied that horizontal well system was marginally more suitable in addition to other benefits for the given field with given conditions which in other words signifies that the horizontal well system's efficiency wasn't upto the desired level and needs severe improvement.
Stimulated Shale Volume Characterization: Multiwell Case Study from the Horn River Shale: I. Geomechanics and Microseismicity
Authors: Hurd O. , Zoback M. D. 
Published: October 2012

Abstract
We carried out an integrated geomechanical and microseismic analysis of a gas shale production pad in the Horn River Basin containing 16 horizontal wells, over 270 individual hydraulic fracture stages, and more than 15,000 located microseismic events to better characterize the reservoir response to hydraulic fracture stimulations. Geomechanical constraints indicate that the pad is generally characterized by a strike-slip stress regime (SHmax &gt; SV &gt; Shmin) with the maximum horizontal stress (SHmax) oriented NE-SW. A pre-existing NNE-SSW-trending fault passes through the pad and appears to be well-oriented for slip in the current stress field. Measurements of Shmin, the minimum principal stress, are moderately elevated in some stages in the vicinity of this fault, and also appear to gradually increase from toe to heel in most wells. Microseismic b-values, which quantify magnitude scaling relationships for a population of events, vary from stage to stage but typically range between 1.0 and 2.5, indicating a relative abundance of small magnitude to large magnitude events compared to naturally-occurring earthquake populations (b ≈ 1.0). This observation has also been reported in other shale gas stimulation projects. We also utilize the double-difference relocation technique in an attempt to improve the accuracy of microseismic event hypocenters recorded during individual hydraulic fracture stages. The technique produces a clear hypocenter lineation, which unfortunately appears to be an artifact arising from the limited monitoring array configuration and not an actual structure within the reservoir. Finally, we analyze a population of microseismic events recorded during a single hydraulic fracture stage and find that the events can be broken into small sub-groups of events based on high waveform similarity, which suggests repeated slip on small-scale reservoir structures. We conclude that reservoir response to hydraulic fracturing is generally characterized by seismic deformation occurring on small fractures created or reactivated by the hydraulic fracturing stimulations, although there is also some evidence for seismic deformation occurring on larger-scale localized structures within the reservoir.
A Fresh Look at Completion Reliability Supports Sand Control Selection
Authors: Capderou Christian , DiLorenzo Neil 
Published: October 2012

Abstract
Although several publications provide reliability estimates based on a constant rate of failure (CFR), the results remain controversial. The use of published results in completion selection and Reliability Availability Maintainability analyses (RAM) is often challenged by industry peers.
This study sets out to generate reliability estimates for three sandface completion techniques applicable to horizontal oil producer wells in unconsolidated sands: Open Hole Gravel Pack (OHGP), Expandable Sand Screens (ESS) and Cased Hole Oriented Perforating (CHOP). The data set included subsea and platform wells (including deepwater fields) from several regions of the world using a consistent definition of failure.
The team first conducted a survey across operated and non operated assets worldwide including subsea deepwater and platform wells and then defined a failure criterion to be used across all sandface completions. The data gathered was then analyzed to select the appropriate Probability Distribution to represent variable failure rates.
This fresh look at sandface completion life data found that OHGPs are a much more reliable sandface completion option compared to ESS. OHGP completions are estimated to have a mean time to failure (MTTF) of 29.0 years (5.3 years to 52.7 years with 95% confidence). ESS completions in this dataset have a MTTF of 6.2 years (3.8 to 8.6 years with 95% confidence). The results obtained for CHOP could not be directly compared to OHGP and ESS due to limited data available.
The results from these analyses were used along with other value drivers to support the sandface completion selection for a Major Capital Project (MCP). The life distributions found in this study were also used to build a RAM model for major capital projects – providing life of field OPEX and well availability (percent uptime) estimates.
Effect of Multicomponent Adsorption/Desorption Behavior on Gas-In-Place (GIP) Calculations and Estimation of Free and Adsorbed CH4 and CO2 in Shale Gas Systems
Authors: Das Mita , Jonk Rene , Schelble Rachel 
Published: October 2012

Abstract
Unconventional shale gas resources have become a major component of the energy mix in North America, with future growth projected globally. The nature of storage and transport of hydrocarbon gas are not yet fully understood in these plays. Adsorption in gas shales is expressed by the Langmuir isotherm, which is the capacity of the rock to adsorb gas at any given temperature. The Langmuir isotherm is generally measured in the laboratory with crushed rock samples. In the presence of CO2 with CH4 in the free gas state, the desorption behavior and measurement becomes more complex.
There are significant differences in sorption experimental procedures and results reported by different vendors. This study addresses the challenges in data variability in sorption measurement, the differences in EUR and GIP calculations, including existing limitations on adsorption measurement and reporting techniques. The results and implications of round- robin experiments with four different samples across four vendor laboratories are shown with multi-component adsorption isotherm analysis. The limitations and variations based on vendor data measurement techniques for accurately calculating GIP and EUR in the case of multi-component adsorption are discussed.
The Evolving Unconventional Gas in China
Authors: Wang Xiuli 
Published: October 2012

Abstract
Natural gas is emerging as the premier fuel of the world economy and will play a pivotal role in China. China, the pre-eminent industrialized nation of the era, needs new and very large energy supplies and currently does not even come close to supply adequate indigenous resources in both quantity and variety. Coal still overwhelmingly dominates the energy mix, causing both major economic and environmental complications. Energy will be "China's choke point" on its path of becoming a world power.
Today, natural gas accounts for only a small fraction of the Chinese energy mix. With a share of 4 percent, natural gas will have to grow to 10 percent through a government edict by 2020. The volume of gas needed will be staggering.
This paper describes the current state of natural gas in China and its evolutionary history during the past two decades with an attempt to forecast the future over the next decade. Emphasis is placed on technical problems and challenges in natural gas development, particularly in the exploration and production of shale gas. A basin analysis is done to compare the characteristics of potentially producing basins in China with those in the United States. Technological demands are identified and production capability is forecasted.
It is the author's belief that to maintain China's current economic growth of 10 percent, China needs to greatly expand its natural gas use and produce much of it locally. This can be done only by emulating North America, not just by adapting existing technologies but also by developing economies of scale and cost-cutting efficiencies to fit in China's own situation. This is the only way that China can speed up its domestic natural gas production, especially in shale gas developments.
Gas Breakthrough Detection and Production Monitoring From ICD Screen Completion on Lukoil's Korchagina Field Using Permanently Installed Distributed Temperature Sensors
Authors: Chertenkov M. , Deliya S. V. , Semikin D. A. , Brown G. A. , Bayanova A. , Kanevsky E. , Nukhaev M. , Shapovalov A. , Pormeyster Y. 
Published: October 2012

Abstract
Lukoil-Nizhnevolzhskneft is developing its Korchagina oil field in the Russian sector of the Caspian Sea using inflow control device (ICD) sand screen completions producing from horizontal wells. The ICD completion is used to delay gas and water breakthrough and extend the well's production life. Offshore operations, restricted wellhead access and a relatively low TVD limit conventional production logging possibilities, so Lukoil has chosen to install permanent fiber-optic distributed- temperature monitoring systems with its sand screens and to use these systems to monitor and optimize production.
The optical fiber has been deployed on the outer part of the sand screen shroud in this horizontal, low-drawdown well. Installing the fiber outside the ICD sand screens gives a unique direct measurement of the inflow temperature from individual well zones (the effect of Joule-Thomson warming/cooling of the flowing fluids caused by the pressure drawdown), excluding the effects of thermal mixing of the reservoir fluid flowing inside the wire-wrapped screens. This inflow temperature responds directly to zone drawdown and fluid Joule-Thomson properties, allowing these properties to be monitored over time.
Descriptions are provided of the completion technology used to install the fibers along the ICD sand screens and of the data and results obtained. Thermal models of the near-well environment are also described and are used to analyze the data for early detection of the gas breakthrough and to allow real-time production optimization. The installed optical fiber proved its value for production optimization in this ICD completion in the Korchagina oil field.
Dual-Continuum Modeling of Shale and Tight Gas Reservoirs
Authors: Azom Prince N. , Javadpour Farzam 
Published: October 2012

Abstract
Shale and tight gas reservoirs are characterized by very low permeabilities at the nano-scale which gives rise to non-Darcy effects such as Knudsen diffusion that makes the use of conventional (Darcy) models inadequate. Slip-flow and Knudsen diffusion have been shown to be accounted for in an apparent permeability that is not just pressure dependent but can be strongly non-linear. Available apparent permeability models are either an empirical function of the matrix permeability or capillary tube models based on the ideal gas law. We use the latter in this work but correct for real gas and porous media effects. Incorporating slip-flow and Knudsen diffusion in developing a dual-continuum reservoir simulator capable of modeling natural fracture flows in shale and tight gas reservoirs is tricky because the matrix-fracture interporosity term can no longer be treated as the historic constant for single phase flows but as a complex function of pressure. In this work, we show that we can circumvent this complexity only if we use a modified pseudo-pressure approach and treat the resulting variable diffusivity as an explicit term in the derivation of an adequate matrix-fracture interporosity shape factor. We also develop a 2D implicit compositional single phase dual-continuum reservoir simulator suitable for modeling naturally fractured (or fissure rich hydraulically fractured) shale and tight gas reservoirs. Our results show that natural fractures (and/or fissures) can play a very crucial role in shale and tight gas recovery, which is significantly enhanced by slip-flow and Knudsen diffusion and hence, should not be ignored. Our model can also be used to model flows through the hydraulic fractures for situations where hydraulic fracturing is dense and hence present a computational challenge to model explicitly.
Advancements in Openhole Completion Technology Increase Efficiencies and Production in the Williston Basin
Authors: Paneitz John , Johnson C. Christopher , White Matthew , Gentry George 
Published: October 2012

Abstract
Unconventional reservoirs require innovative completion techniques and technology to become more economical. Formations vary drastically in lithology, lateral lengths, completion methods, and financial drivers. The two most popular stimulation techniques are ‘plug-n-perf’ and multistage openhole packer/sleeve completions.
The Williston Basin consists of two primary oil- and gas-producing formations: Bakken and Three Forks. As frac sleeve designs have improved, the capabilities to offer operators an ever-increasing number of stages in a one-trip system have vastly increased the effective flow area created by staged hydraulic fracturing, thus resulting in better production.
Over the years, hybrid systems have been installed in horizontal wellbores to increase the number of compartmental sections for hydraulic fracturing because of the limitations of ball-actuated frac sleeves. These hybrid systems place ball-actuated frac sleeves along sections of the wellbore starting at the toe. Once the maximum number of frac sleeves has been spaced out using openhole packers for isolation, the additional sections of the wellbore are separated without sleeves using only openhole packers. During the frac, balls are used to shift open frac sleeves and provide isolation from the previously treated sections. Once all the sleeves have been opened and the fracs placed, composite frac plugs are pumped down and set to isolate and treat additional stages using the ‘plug-n-perf’ method. Experimenting with hybrid systems provides operators with the ability to optimize spacing of frac stages along the horizontal section when sleeve technology alone did not allow for the desired number of stages. The costs are higher for operators to perform a hybrid-type completion, and this has driven enhanced sleeve technology to allow for all sleeve completions.
Working relationships between operators and service companies have enabled the advancement of current technology to provide solutions that increase efficiencies and production. This paper outlines information from specific case histories on current well construction/design, historic overviews showing the progression of openhole completions used within the Williston Basin, how spacing is determined between stages based on reservoir characteristics, and how technological advancements and working relationships have enabled a record number of sleeves to be installed in a single wellbore where tighter frac spacing is required.
Modeling and Dynamical Analysis of the Wave Equation of Sucker-Rod Pumping System
Authors: Yang Yu , Watson Jeff , Dubljevic Stevan 
Published: October 2012

Abstract
The use of sucker-rod pumping systems is the most common method of artificial lift in the oil-well industry. In this work, the viscous-damped-wave equation model has been developed to describe the rod-string dynamical behavior at various well depths utilizing the inputs of load and position originating from the surface-card measurement. In contrast to the existing solutions of viscous-damped-wave equation dynamics, which is based on Fourier series truncation and finite difference method, in this paper a novel technique is presented and utilized in the real time estimation framework. In particular, an infinite-differential state space representation of the viscous-damped-wave equation dynamics is developed based on appropriate boundary transformation. The spectral decomposition and truncation of an infinite number of modes is realized, so that the partial differential equation model is cast to the system of coupled ordinary differential equations, which can be solved in real time and utilized for period and non-periodic motion stroke. Finally, the new method is validated by the real case study associated with the existing well.
Mini-DST to Characterize Formation Deliverability in the Bakken
Authors: Kurtoglu B. , Kazemi H. , Boratko E. C. , Tucker J. , Daniels R. 
Published: October 2012

Abstract
Characterization of reservoir deliverability is fundamental for the economic development of any field. In the Bakken, there is a need for reliable pressure transient tests to provide the effective formation permeability of the fracture-matrix in this formation for deliverability calculations. This effective permeability can then be compared to laboratory measured core permeability of the matrix rock samples. This comparison is the basis for planning early production options and subsequent enhanced oil recovery (EOR) decisions. This comparison is particularly important because of the influence of massive hydraulic fracture stimulation on reservoir performance.
Determining well deliverability potential by conventional drill stem tests (DST) or traditional wireline formation tests (WFT) in the past has resulted in mixed success in the Bakken. On the other hand, the mini-DST has definitely increased reliability and the success rate of pressure transient tests. The operation of mini-DST tool requires much less time than the classic DST, and multiple zone tests can be conducted to assess individual zone deliverability. The Mini-DST tool uses the conventional Wireline Formation Tester (WFT) configured with a dual-packer module and downhole pump. Tests are conducted by inflating the dual-packer module to isolate a 3-foot interval of the wellbore. The formation fluid is pumped out from the packer-isolated wellbore interval to conduct pressure drawdown and buildup tests in the interval. An overlay of all the pressure drawdown and buildup results from various intervals is compared on a single plot to identify the most productive interval. Finally, conventional pressure transient analyses are performed to interpret all pressure drawdown and buildup tests. In this paper we present several field tests which were analyzed both by the above procedure as well as by numerical simulation.
The analyses of several mini-DST results have provided insight into a better understanding of the flow mechanism in the Bakken both during primary production and in forecasting various improved and enhanced oil recovery proposals. The experience can also serve as a basis for test design in similar low-permeability reservoirs elsewhere.
Mapping of Hydraulic Fractures under Triaxial Stress Conditions in Laboratory Experiments using Acoustic Emissions
Authors: Damani Akash , Sharma Abhishek , Sondergeld Carl , Rai Chandra 
Published: October 2012

Abstract
Hydraulic fractures are traditionally modeled as planar features developed by the tensile failure of the rock. Laboratory nanoseismic and field mine-back studies show that most of the fractures are non-planar complex features. Fracture properties are strongly affected by the magnitudes and directions of the stresses in the formation. Low stresses are associated with a complex fracture development while high stresses create simpler, straighter and more planar fractures.
We report the results of controlled laboratory triaxial hydraulic fracturing experiments instrumented with piezoelectric sensors. We performed tests on Lyons sandstone which was determined to have an initially isotropic velocity structure. The fracturing experiments have been performed under triaxial stress state to replicate the insitu stress reservoir conditions. The uncertainty in hypocenter locations, frequency analysis, source mechanisms and the effects of stress on fracture propagation will be discussed. Microscopic observations of the fractures are correlated with the mapped microseismic events. Fractures are observed to be non-planar visually and at the SEM scale. Shear failure recorded by focal mechanisms appears to dominate the failure mode. The deviation from planarity will surely affect proppant transport and dispersement.