bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analysis of Geomechanical Data for Horn River Basin Gas Shales, NE British Columbia, Canada
Authors: Chou Queena , Gao Jordan , Somerwil Mick 
Published: February 2011

Abstract
Geomechanical data from the public domain for offset wells in the Horn River Basin, north–east British Columbia, Canada, were analyzed to obtain in–situ stress and rock mechanical properties in Devonian gas shale members that are under development. Static rock mechanical properties (e.g., Young’s modulus, unconfined compressive strength, peak cohesion) were calculated from wireline logs from offset wells for the shale members of interest. Derived static Young’s moduli for these shale members range from 18 to 31 GPa, and estimated unconfined compressive strength values range from 41 to 63 MPa. Assuming an average peak friction angle of 35°, the calculated peak cohesion values range from 11 to 16 MPa.
From three offset wells, the average vertical stress gradient at the top of the Devonian shales was estimated to be 24.8 kPa/m. Borehole breakouts and anisotropy of the sonic log velocities from offset wells were analyzed to estimate the current orientations of the in–situ minimum and maximum horizontal stresses. The predicted orientations of the in–situ horizontal stress were compared to the well azimuths of drilled offset horizontal wells surrounding the property of interest. This regional data show that the dominant orientation of the in–situ minimum horizontal stress is NNW–SSE. Hence, hydraulic fractures will propagate perpendicular to this in an ENE–WSW orientation. The average orientation of the horizontal wells drilled by the other operators in the basin to date is NNW–SSE, with a wide scatter of other well orientations. There was insufficient data in the public domain (e.g., oriented caliper logs) to assess whether orientations or magnitudes of the horizontal stress vary over the basin, or whether they are affected by small or large faults.
The average contrast of the magnitude of the horizontal in–situ stress between the shale members of interest was determined from the dynamic Poisson's ratio to understand the propensity for a hydraulic fracture to grow vertically out of zone. The result suggests relatively small contrasts may exist between the shale members. Recommendations were provided for obtaining site– specific in–situ stress data and rock mechanical properties.
Technical Limits of Tight Gas Fracturing in Oman – An Innovative Exploration Approach that Incorporates Global Practices
Authors: Curtino Joe , Harianta Rudi , Lie Winarsa , Judd Tobias 
Published: February 2011

AbstractIn Oman, hydraulic fracturing is an established tight gas completion technique in which fluid viscosity is used to build the necessary fracture geometry and transport proppant toward the fracture tip. This process has been very successful in reservoirs that demonstrate high gas permeability values and display normal stress regimes. However, in the deeper, hotter, lower-productivity horizons, these techniques are less effective.A data collection and engineering method is required for local exploration and appraisal wells in this area because some of the tight gas reservoirs display unique physical properties that prevent actual analogue comparisons with other developed reservoirs. Furthermore, current industry practices, which are primarily influenced by the North American tight and unconventional gas market, merely transfer and apply different types of fracture design techniques. Here though, an engineering process is necessary to account for the reservoir properties and the potential impact on post fracturing well performance, along with potential scenarios for treatment failure.Recent discoveries have occurred in the deep Amin formation that has resulted in an improved fracture design process. The technical challenges of fracturing a deep, high-pressure, high-temperature formation required evaluating alternative stimulation approaches than the traditional crosslinked gel fractures. This included deploying a high-density, crosslinked fracturing fluid incorporating a weighted sodium bromide–base fluid to generate high bottomhole pressures required to frac while not exceeding completion limitations. Likewise, the application of abrasive perforating technology has resulted in success where previous attempts using conventional techniques were not successful because of high near wellbore frictions and stresses. Finally, the evaluation of a hybrid fracturing technique has improved understanding of reservoir behavior in relation to hydraulic fracturing performance.The continued emphasis and focus on low-permeability sandstone reservoir in this work is justified and useful by the continued importance of these reservoir types in Oman and other Middle East countries.
Detailed Modeling of the Complex Fracture Network of Shale Gas Reservoirs
Authors: Gong Bin , Qin Guan , Craig Douglas , Yuan Shiyi 
Published: February 2011

Abstract
Hydraulic and natural fractures are the key channels for shale gas to flow at economic rates. Fracture growth in shale gas reservoirs appears to be much more complex compared to most conventional reservoirs as massive multistage, multicluster hydraulic fracturing treatments are executed at many shale gas formations. It becomes crucially important to develop advanced approaches to model and simulate such a complex system to better understand the recovery mechanisms and optimize stimulation designs of shale gas reservoirs.
Most existing shale gas models are idealized dual-porosity models. The objective of this work is to model the actual network of hydraulic and pre-existing fractures based on geological interpretations and microseismic mapping results. The Discrete Fracture Modeling (DFM) approach is applied to represent each fracture individually and explicitly. This requires unstructured gridding of the fracture-matrix system using Delaunay triangulation and transmissibility evaluation between each pair of adjacent cells. The near-well effects are modeled in detail by refining the unstructured 3D grid to the point where we fully resolve stimulated fractures.
Simulations have been performed based on the detailed model of an synthertic shale gas reservoir with considering various mechanisms including adsorption/desorption, matrix-fracture transfer, and non-Darcy effects. Sensitivity studies by varying the production rate, pressure and hydraulic fracture parameters are conducted to provide guidance on optimizing stimulation and production schemes. Furthermore, to extend the application of this technique to large models, the Multiple Subregion (MSR) upscaling procedure is proposed to enable much quicker simulation runs. The high degree of accuracy provided by this technique is demonstrated by comparing the solution of the upscaled model with the corresponding fine-grid solution for a synthetic case.
Hydraulic Fracturing: Key to Effective Khazzan-Makarem Tight Gas Appraisal
Authors: Rylance Martin , Nicolaysen Arild , Ishteiwy Omar , Judd Tobias , Huey Troy , Giffin Wade 
Published: February 2011

Abstract
All tight gas project appraisals are inherently dependent upon the ability to execute effective fracturing treatments; that allow the determination of sustainable production rates; and hence potential project economics. Unlike the North American tight gas business, where thousands of wellbores are drilled each year and operational infrastructure and service quality is proven and in place; the International gas market challenges are significantly different. Often, the key risk with international appraisal; is not the presence of the hydrocarbons themselves, but more likely a competent and efficient execution of the fracturing process; that is essential in order to maximize gas inflow performance required for optimum well productivity.
The Khazzan-Makarem structures have substantial known hydrocarbon reserves; which to date have resisted an economic development. The unique reservoir challenges of these formations have been shown to require specialised operational, execution and technical expertise in order to be successfully appraised. The approach taken by the operator was to design the appraisal project with particular emphasis on the application of massive hydraulic fracturing treatments; as without successful stimulation, it was appreciated that the ability to evaluate well productivity and hence the development potential would remain elusive.
The result of close cooperation between the operator and the service providers, included planning the stimulation strategy, the number/sequence of wells, well types, fracture design, development of a matrix and selection criteria for technology deployment as well as operational issues associated with individual treatment execution. A locally tailored and carefully planned workflow was developed, that addressed the fracturing design process, the impact on the service delivery and the overall performance of this extensive project.
Information presented within this paper, will provide a complete understanding of the specific factors involved in tight gas stimulation (particularly in remote areas). Furthermore, it will demonstrate a methodical approach to the process of planning, execution, QA/QC and post treatment assessment.
North Oman Deep Gas Exploration Opportunity: From Drawing Board to Drilling Activity
Authors: Walton William , Scholten Sven , Aitken John , Al-Hakmani Abdullah , Al-Siyabi Hisham , Skaloud Dieter , Millson John 
Published: February 2011

Abstract
Early Palaeozoic-age non-associated gas fields operated by Petroleum Development Oman (PDO) in the Sultanate of Oman have traditionally comprised good reservoir quality sandstones located on three- or four-way dip-closed structural highs. While gas exploration success has continued over the last five years, this has been restricted to discoveries in much poorer quality ("tight") sandstone reservoirs. Significant challenges exist: target reservoirs are deep - over 4500 m (18,000 ft) with high reservoir temperatures (&gt; 170°C). Porosities range from less than 3 to 10% with (ambient) permeabilities ranging from 0.001 to 1 mD.
These tight reservoirs have elevated pressures (above hydrostatic) and many wells record GDT (Gas-Down-To) situations (i.e. no GWC recorded). Furthermore, basin modelling indicates that peak hydrocarbon generation occurred during the Palaeozoic and Mesozoic and may have continued until Early Tertiary times in some areas.
A study was started in 2008 to analyse the above data applying a range of techniques including basin modelling, geochemistry, regional well results evaluation together with pressure data analysis and comparison with global analogues. This resulted in approval for a four well exploration campaign to evaluate diverse locations across north Oman addressing the quest for tight gas in a basin-centre setting. Drilling of the first exploration well started in late 2009 with the aim of proving the presence of deep gas accumulations and ultimately gain an indication of commercial attractiveness.
This paper presents the key criteria expected to influence the deep gas play prospectivity (i.e. presence of favourable reservoir, hydrocarbon charge and retention) and the steps to mature this opportunity. We also highlight an approach to progressing an unconventional gas opportunity in a challenging geological environment, in the Middle East, where the maturation of this resource type is currently in its infancy.
Petrophysical Rock Typing of Tight Gas Sands - Beyond Porosity and Saturation: Example from the Cotton Valley Formation, East Texas
Authors: Spain David R. , Liu Shujie , Devier Chuck 
Published: February 2011

Abstract
Laboratory benchtop nuclear magnetic resonance and mercury injection capillary pressure measurements were made on representative core plugs to facilitate rock property modeling of East Texas Jurassic Cotton Valley tight gas sandstones. NMR provides porosity data that is calibrated to downhole NMR and bulk density porosity measurements. Combined with mercury injection data, NMR provides information on the pore body -pore throat network characteristics of the reservoir sandstones. These data, combined with routine core data and petrographic observations, show that the Cotton Valley sands have low permeability, but that they are probably not capable of allowing water-free production.
Mercury injection data indicate that the bound (irreducible) water saturations in these rocks should be greater than 90% of the total Sw. This means that most of the water in the formation should be held in the reservoir by capillary forces and that gas production from these rocks should be relatively water-free. This is not the case.
NMR data indicate that there could be substantial water production with little gas flow. Combined data indicate that the reservoir sandstones have small to medium sized pores with small to medium pore throats. The rocks have low porosity and permeability overall, but are not tight enough to hold most of the formation water in the reservoir. Primary depositional facies, clay content, and subsequent diagenesis created complex pore geometry. NMR responses are controlled by the pore sizes; mercury injection behavior is controlled by pore throat diameters.
Improved permeability / petrophysical rock type models have been derived and used to calibrate downhole NMR measurements in both vertical and horizontal wells, resulting in improved recoverable gas in place estimates, fractional flow predictions, well targeting, and completion optimization in horizontal wells.
Aspects of Seismic Prospecting in Tight Gas Reservoirs
Authors: Philip Neil , Sheard Emma , Sutherland Fiona , Roome Barnaby , Taylor Brian , Margesson Richard 
Published: February 2011

Summary
This paper describes some of the seismic aspects of BP’s experiences developing and exploring tight gas in Algeria. BP are involved in two projects where seismic has played a key role. The first project is a known gas field in its development stage, which requires infill well locations. The second is in its early exploration stage and requires a more fundamental understanding of the reservoir architecture.
Enhanced Geomechanical Modeling with Advanced Sonic Processing to Delineate and Evaluate Tight Gas Reservoirs
Authors: Adisornsupawat Kanitthorn , Tan Chee Phuat , Anis Leo , Vantala Aurifullah , Juman Reayad , Boyce Barry 
Published: February 2011

Abstract
A South East Asia exploration well was drilled into a gas-bearing large anticlinal 4-way Jurassic and Triassic age continental clastic with marine incursions. The well was designed to evaluate gas in tight sandstone with fractures. The host rock overall had low matrix permeability. Conventional methods of gas production from tight reservoirs usually require artificial stimulation such as some form of hydraulic fracturing. This well was no exception.
In order to optimize the hydraulic fracture design, a 1-D geomechanics study was requested to estimate hydraulic frac-ability of the rock. A 1-D Mechanical Earth Model (MEM) was constructed and fracture breakdown pressure was estimated as an outcome of the model. Mechanical properties are derived from logs data and calibrated against core with rock mechanics test data. Advanced sonic processing conducted before and after the fracing which give estimated pre- and post hydraulic minimum and maximum horizontal stress. These data was used to calibrate horizontal stresses profiles derived using poro-elastic strain models. The shear radial profiling was carried out allowing for identifications of the existence of stress within the rock. The advanced sonic processing also revealed the characteristic of stress anisotropy in the formation. Hydraulic fracture design and procedure was then developed based on the results of the model.
This paper intended to present the MEM using outputs from advanced sonic processing to narrow down the uncertainty of geomechanics parameters that are exist in the model.
Application of IFOT in Tight Gas as a Reservoir Surveillance Technique
Authors: Pinto E.. , Adams J. R. 
Published: February 2011

Abstract
Tight gas reservoirs are characterized by very low matrix permeability. In these types of reservoir systems long shut in periods are required to establish pseudo radial flow making conventional well testing methods impractical. This is especially true once the well has been hydraulically fractured due to the added flow complexity and the resultant additional time required to reach pseudo radial flow.
Injection fall off test (IFOT) is a pre frac injection technique that can be used to estimate reservoir pressure and get a qualitative estimate of formation permeability-thickness (k*h) in tight gas reservoirs. This is somewhat equivalent to a cleanup flow on a DST (Drill Stem Test); the idea is to establish flow to the reservoir, get the well-bore fluid to a known density, restrict the flow duration to minimize the reservoir volume affected by the flow, and shut-in long enough that the Horner/Superposition plot extrapolation is as small as possible.
BP has applied this technique to infill Cotton Valley (CV) wells in the East Texas Basin in order to get an updated value of reservoir pressure for use in material balance depletion analysis, amongst other applications. After successful implementation of this technique in vertical and horizontal tight gas sandstone wells, the testing method was extended to three Cotton Valley Lime wells and also to the first BP Haynesville Shale vertical well. This document summarizes field examples that illustrate the analysis and application of this IFOT technique in both vertical and horizontal wells including the test results on the Hayneville shale well. In the latter, the application of the test results on basic reservoir simulation is also discussed.
Improving In-Situ Horizontal Stress Profile Accuracy Using Multi-Mode Sonic Measurements: A Case Study in a Deep Tight Gas Well in Saudi Arabia
Authors: Luo MaoLin , Wu Haojie , Mohiuddin Mohammed A. 
Published: February 2011

Abstract
The magnitude and direction of in-situ horizontal stresses are crucial parameters for a successful hydraulic fracture design and operation that are often conducted in tight unconventional reservoirs. The Poro-Elastic Horizontal Strain method where the minimum horizontal stress magnitude is calibrated to closure pressure from extended leak off test or leak off test is commonly used to estimate the horizontal stress profiles. However, in exploration areas it is common that calibration data is very limited or missing, hence horizontal stress calibration from other sources like multi-mode sonic measurements becomes useful.
This paper presents a recent application of using multi-mode sonic log acquired in a deep vertical exploration well in Saudi Arabia to determine in-situ stress profile for the design of hydraulic fracturing job in a tight gas reservoir. The azimuth of fast shear was used to determine maximum horizontal stress direction, whilst, horizontal stress gradients were determined using Velocity Dispersion Gradient (VDG) method at five intervals where the acoustic anisotropy is predominantly stress-induced. Subsequently, a Mechanical Earth Model was constructed in which the horizontal stress estimated using Poro-Elastic method was calibrated to horizontal stress gradient from VDG method at the five intervals. The minimum in-situ horizontal stress profile was later confirmed by the closure pressure from MiniFrac test and the hydraulic fracture height indicated by the temperature log. The difference in magnitudes between minimum in-situ horizontal stress and closure pressure at the perforation zone was 1.2%, and the hydraulic fracture height agreed with the minimum in-situ horizontal stress profile.
Considering that the multi-mode sonic logs are commonly acquired to derive compressional and shear slowness, the VDG method can then be used to improve the accuracy of horizontal stress profile without any additional rig cost to operators.
A New Method for Low Permeability Gas Well Performance Prediction Using Pressure Transient Analysis: Theory and Practices
Authors: Hedong Sun , Xu YanMei 
Published: February 2011

Abstract
The performance predictive target is always too optimistic using the LIT equation and material balance equation for the supply, multi-layer and other non-homogeneous low-permeability gas reservoir. To solve this problem, the project intends to start from the theory of pressure transient testing to establish different types of non-homogeneous gas reservoir performance prediction theoretical model, to explore optimization algorithm. The overall objective is to establish a more realistic dynamic prediction theory. It can improve the early prediction results for non-homogeneous gas reservoir, and this theory is considered non-homogeneous gas layer or regional non-homogeneous variables, but also simple and quick to predict the dynamic change of pressure and gas rate. New method is amended by numerical simulation. A single-well radial/composite model is constructed with measured rock and fluid properties. This compositional simulator is used to generate synthetic pressure transient data which are subsequently interpreted in well testing package. The impacts of test time and reservoir heterogeneity on prediction results are investigated. Through theoretical analysis and numerical simulation, the mechanism for gas flow, the pressure, the output rate variation over time is analyzed. A low permeability gas wells are analyzed by new method, thus improving long-term well performance predictions.
Histochemical and enzyme-histochemical studies of Oncomelania hupensis (Gredler, 1881), the intermediate host of Schistosoma japonicum
Authors: Wang Wei , Dai Jianrong , Li Hongjun , Liang Yousheng 
Published: February 2011

AbstractThe distribution of glycogen, DNA and histone, and localization of activity of ten enzymes such as glucose-6-phosphatase (G-6-Pase), cytochrome oxidase (CCO), lactate dehydrogenase (LDH), 5′-nucleotidase (5′-NT), succinate dehydrogenase (SDH), glucose-6-phosphate dehydrogenase (G-6-PDH), alkaline phosphatase (ALP), acid phosphatase (ACP), Mg2+-adenosine triphosphatase (Mg2+-ATPase), and cholinesterase (CHE) in Oncomelania hupensis (Gredler, 1881) snails, the intermediate host of Schistosoma japonicum, was surveyed using the histochemical and enzyme-histochemical techniques. The results showed that the glycogen with high activity was widely distributed in snails. DNA showed its strongest reaction in testis. The histone was distributed in sites of the radula, parenchyma of penis and ovary. LDH and SDH were widely distributed in snails and all were abundant. Sites of the strongest enzyme activities of G-6-PDH were evident in the reproductive system together with central ganglia. Only the ovary showed a strong enzyme activity of G-6-Pase. Most tissues and organs contained CCO, and the activity of this enzyme was very strong. 5′-NT showed a strong enzyme activity in the ovary and testis. Mg2+-ATPase was localized in sites of the liver, stomach and reproductive gland. A strong enzyme activity of ALP appeared in the digestive system. ACP showed a low activity in snails. The central ganglia, nervous stem, liver, branchial duct, epithelia of the head and foot regions showed a very strong enzyme activity of CHE. The findings could provide a theoretical basis for development of highly effective molluscicides with low toxicity to other biota, as well as means for novel snail control strategies.