bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mechanical Interaction of Multiple 3D Fractures Propagation for Network Fracturing
Authors: Sun Zhiyu , Liu Changyin , Huang Zhiwen , Zhang Rusheng 
Published: November 2015

Abstract
Multiple cluster perforations are typically used for multi-stage hydraulic fracturing of horizontal wells with casing hole completion to create multiple fractures in any single stage. Due to the mechanical interaction of fractures, the local principal stresses field may alter, which affects the fracture complexity. To optimize the network fracturing design, 3D multiple fractures propagation, stress distribution and fracture mechanics need to be well considered.
Firstly, The geometry model for Fuling shale gas formation has been Established, with A depth varying initial in-situ stresses, pore pressure and permeability defined. Then, a linear Drucker-Prager model with hardening is chosen for the rock, while the casing is linear elastic. Based on damage initiation of quadratic nominal stress criterion and damage evolution of B-K critical energy release rate criterion, the tensile and shear mixed mode fracture model consists of the mechanical behavior of the fracture itself and the behavior of the fluid that enters and leaks through the fracture surfaces.
Through the selection of general purpose finite element code ABAQUS, the multiple 3D fractures propagation process and stress interferences between fractures have been modeled. The results illustrate that mechanical interaction exists between any pairs of fractures, which greatly influences the stress distribution and the geometries and widths of the fractures. Induced stress increase is stronger in magnitude and influences larger region for the minimum horizontal stress than for the maximum horizontal stress. Spacing of perforation clusters and net pressures are two important factors for the successful application of network fracturing. It is possible that the cumulative interaction effect of several fractures could neutralize the stress anisotropy in the formation to enhance the fracture complexity. Taking advantage of the altered stress in the rock for a base case with three fractures, an adequate range of perforation clusters spacing and net pressure are determined for the network fracturing of horizontal wells in Fuling shale gas reservoir, and the treatment design is optimized accordingly.
This numerical procedure combined with the post-fracture production rate is also used to evaluate the efficiency of network fracturing for multi-stage fractured horizontal wells in Fuling formation, which can be served as a guidance to optimize the treatment design not only for Fuling but for other shale gas and tight gas reservoirs.
A New Improved Shale Correction for Pulsed-Neutron Measurements
Authors: McIlroy Chris , Quirein John , Mekic Natasa , Guo Weijun 
Published: November 2015

Abstract
The addition of a third detector to pulsed-neutron tools (PNT) enabled a new measurement, saturation gate (SATG), which is sensitive to gas vs. fluid. The saturation calculation was originally created using a single mineral model of clean sandstone in which it worked well. Sandstone formations typically have some shale content and as the shale content increased, the gas saturation algorithm undercalled gas saturation. An updated two mineral model, taking into account both sandstone and shale, is needed to accurately calculate gas saturation in shaley-sandstone environments.
Two methods are being introduced to correct for the shaley-sand effect. The first method uses a crossplot technique of sandstone to shale SATG data vs. the volume of shale and corrects the shale affected points back to the sandstone fan. The second method creates two fans: one for 100% sandstone and the other for 50% shale, and the fans are moved to fit the data. The first method results in a straightforward ratio of the change in SATG to the change in shale volume to plug into the correction while the second method is both more intuitive in context and interpretative in practice. The shale is modeled using a mixture of 50% illite clay and 50% quartz. Depending on the mineralogical composition of the shale, other fans could be constructed.
Two tight-gas shaley-sand examples are used to compare the gas saturation response using both the single (no shale correction) and shaley-sand mineral models. Results show the updated model enhances accuracy of gas saturation in shaley-sand environments.
Previous pulsed-neutron sigma and carbon-oxygen saturations had limitations. Sigma-based saturation can calculate both gas vs. water and oil vs. water saturation but is limited to high salinity formations in which the dynamic range is large. Carbon-oxygen-based saturations are not affected by salinity but only work for oil vs. water saturation. SATG saturation fills a void for gas vs. fluid saturation in low, mixed, or unknown formation water salinities.
An Accelerated Immersive Capability Development in Unconventional Shale Resource
Authors: Biron Azaumi , Befus Robert Alexander , Stannard James , Navarette Mike , Singh Seemant , Salahudin Sharifudin 
Published: November 2015

Abstract
The unconventional revolution in North America has attracted large investments from national oil companies (NOCs) and international oil companies (IOCs) eager to gain knowledge and add profitable unconventional resources to their asset portfolios. A key element of realizing this goal is the rapid and effective development of in-house technical personnel to support the effort. In 2008, a major NOC in Asia began its unconventional quest with an initial entry into a coal seam gas (CSG) opportunity in Australia, followed by investments in shale gas plays in the prolific Canadian North Montney area. To develop the much needed in-house capability, the NOC partnered with a major service provider to develop and deliver training programs to prepare its geoscientists and engineers to work within the unconventional division.
Previous efforts by the NOC to develop in-house unconventional capabilities were hampered by a lack of data specific to their joint-venture shale assets. The newly established Unconventional Division had recently acquired an interest in Canadian Unconventional assets, and challenged the joint team to design a capability development program that would utilize this data, deliver practical experience, and build critical staff knowledge, in less than 6 months. The NOC agreed to provide data from their Canadian asset to enable the development of an accelerated, immersive program.
The redesigned 10-week program used a source rock reservoir development workflow that incorporated a geoscience and engineering software suite to enable participants to review the field data and evaluate optimization opportunities. The goal-oriented tasks were to evaluate the project areas and develop the in-place gas resource to reach plateau production.
The program was conducted entirely in Kuala Lumpur at the service provider's offices between September 8 and November 20, 2014, with development plan results presented to the NOC's management in Kuala Lumpur and Calgary. This paper presents the program development, challenges encountered through the preparation and deployment, final outcomes, and lessons learned.
Impact of Multistage Fracturing on Tight Gas Recovery from Saudi Arabian High Pressure High Temperature Carbonate Reservoirs
Authors: Rahim Zillur , Al-Kanaan Adnan , Al-Anazi Hamoud , Kayumov Rifath , Al-Jalal Ziad 
Published: November 2015

AbstractMultistage fracturing technique has considerably improved gas production from tight gas reservoirs all over the world. Well production is one of the main determining factors to assess the success of a fracturing treatment. In this paper, numerous vertical and horizontal wells drilled in the high pressure high temperature heterogeneous reservoirs have been evaluated to confirm effectiveness of stimulation treatments and benefits derived from the use of novel technologies. Among many variables that were analyzed include drilling, completion, and stimulation parameters such as well azimuth, completion types, fluid characteristics, acid strength, etc.A database for stimulated wells was created and various parameters have been grouped and assessed to provide correlation and understand the effectiveness of fracture treatments and optimize development plan. Correlations were drawn using the Pearson correlation coefficient equation to compute data trend and ensure good quality data. Numerous, very useful plots are constructed and presented that show the different trends of the variables evaluated and how they affect production rate.Analyses results indicate that use of real-time geomechanics is important to predict reservoir pressure and mud weight as wells are laterally drilled in the preferred minimum in-situ stress (σmin) direction. This is because when wells are drilled along σmin, they tend to become more unstable due to the higher stress acting on the wellbore. Accuracy in predicting stresses and pressures are keys to the drilling of such wells. The completion assemblies were selected between open hole multistage and plug and perforation cased hole approaches based of reservoir properties and hole conditions. The impact on production performance by using of non-damaging low gel loading fracturing fluids, high strength proppants, and optimal fluid and acid volumes have been demonstrated using actual field examples. The paper also illustrates the use of novel fracturing approach such as channel fracturing and its impact on sustained gas production in tight gas and making low productivity wells commercial.
Economic and Operational Analysis of Systematically Deploying New Technologies in Two US Unconventional Plays
Authors: Van Sickle S.. , Galloway J.. , McClellan C.. , Snyder D.. 
Published: November 2015

Abstract
An operator working in the STACK and Mississippi Lime plays of the Mid-Continent region in the United States is developing its acreage with the use of open hole multistage (OHMS) completion systems. This paper will detail new technologies and advancements that are providing enhanced economic benefits and enabling the operator to unlock the full potential of the targeted formations.
The operator holds one of the largest acreage positions in the Mid-Continent region and in 2014 had operated or participated in approximately 170 horizontal wells. This operator approached its development with the goal of reducing completion costs; bringing completion costs in line with estimated completion costs; reducing health, safety and environment (HSE) exposure, while reducing cycle time; and preserving estimated ultimate recovery (EUR) of its assets. Some of the new technologies and advancements to achieve these goals include: changing core completion methods, radioactive tracers, dissolvable balls, high-rate water stimulation, extended reach laterals, microseismic analysis, water-soluble tracers, oil-soluble tracers, stage spacing and statistical analyses.
These new technologies and advancements adopted by implementing OHMS completion systems provided the operator with significant cost savings when compared to previous wells completed in the region using cemented liner plug-and-perf techniques. Lessons learned from each well were applied to future wells and the operator realized further cost savings as it continued development of the region using OHMS completion systems. These cost reductions were achieved while preserving the EUR of the assets, increasing the economic viability of the operations.
The technologies, methods and procedures will be presented in this paper to help paint a picture of how this particular operator is leading the way in reducing completion costs and increasing reserves. The details provided will show how OHMS technology is a cost-effective option for operators drilling and completing horizontal wells in the Mid-Continent region of the United States and provide strategies that can be applied in other formations around the world.
Quantifying Pore Size Distribution Effect on Gas in Place and Recovery Using SLD-PR EOS for Multiple-Components Shale Gas Reservoir
Authors: Tolbert Brandon T. , Wu Xingru 
Published: November 2015

Abstract
When a shale gas reservoir is being developed, two fundamental questions need to be answered: (1) how much gas is in place and (2) how much gas can be produced when reservoir is depleted to a specific pressure. This paper examines the pore size distribution impact on gas volume in place during reservoir depletion. A calculation procedure for a multiple component system will be presented with an illustration using Barnett core mercury injection data.
Literature suggests that a monolayer adsorption model is not sufficient for shale gas reservoirs with multiple components in volumetric calculations. In this paper, we propose to use the cylindrical Simplified Local Density model with Peng-Robinson Equation of State (SLD-PR EOS) to solve the local hydrocarbon density distribution for gas in micro-and meso-pores. The integration of the local density over the pore width yields an average density. Pore size distribution (PSD) data such as mercury injection provide the pore volume contribution of different pore radii. Coupling the pore volume distribution with the calculated average density, we calculate the gas in place due to pressurization and adsorption under different pressures. The recovery from the shale reservoir is determined by repeating the process at different pressures. Because of the high non-linearity of the SLD-PR EOS, a trust-region optimization algorithm has been used to solve the local density profile.
Pore size distribution has a tremendous impact on the gas storage capacity of a shale formation. Results from this study reveal that neglecting PSD can yield more than 40% errors for original gas in place (OGIP) calculation. Incremental pore volume is modeled with a Log-Gamma distribution for the Barnett field. OGIP sensitivities to the distribution parameters are also investigated. For the same porosity under the same ambient pressure and temperature, more small pores indicate more gas in place. Therfore under the same depletion process, more recovery can be expected from small pores. This paper utilizes MICP data for a Barnett gas shale core sample to demonstrate the calculation procedure for implementing core data, fluid characterization, and SLD -PR EOS modeling to calculate original gas in place.
This paper has the following two novel points: (1) An improved OGIP calculation procedure for multicomponent gas shales is proposed using the cylindrical form of the SLD-PR EOS model and MICP data from core samples; (2) PSD has a tremendous influence on OGIP values in shale formations because of the presence of micropores and neglecting PSD can yield significant errors in OGIP values.
The Anisotropy and Inhomogeneity of Coal Permeability and Interconnection of Adjacent Seams
Authors: Gray Ian 
Published: November 2015

Abstract
The purpose of this work was to develop a method by which the anisotropy and inhomogeneity of permeability of coal seams and other reservoirs could be rapidly determined at exploration stage. As inhomogeneity can only be determined by multiple tests and anisotropy can only be found by some form of interference test, the intention was to develop an efficient combination of the two.
This was achieved by using drill stem testing (DST) multiple seams in a single borehole followed by the installation of pressure transducers in the coal seams. Another hole was then drilled and DST tested and the transient response in the transducers measured. This was again followed by transducer installation and the drilling of another hole which was then DST tested. Also tested was the interconnection of seams across thin mudstones and a tuff band. The transducer installation was accomplished using cemented in transducers with the cement being displaced in the vicinity of the transducer to establish connectivity with the formation.
The results of the work showed that in the test site inhomogeneity dominated over anisotropy and that the interburden between the seams was highly impermeable. Reliable permeability measurements were achieved by analysing transients of less than 6 kPa (0.86 psi) from a pre and main flow DST.
This process was quick to implement and therefore of low cost. The number of measurements achieved was higher than would have come from a conventional interference test. The multiple boreholes in which flow took place avoided the problem of a conventional interference test, with a single producing hole, which may have been located in a geologically unusual setting.
Minimizing Environmental Pollution while Conserving Oil During Sour Heavy Oil Well Testing - A Novel Approach
Authors: Al-ibrahim Abdullah , Al-Bader Haifa , Razzaq Abdul , Packirisamy S.. , Sagar Vidya , Manimaran A.. , Ibrahim Anwar , Al-Ateeq Abdulla 
Published: November 2015

Abstract

Objectives/Scope
To reduce flaring of produced hydrocarbon during well testing operations in order to protect the environment, comply with safety regulations and conserve oil.

Methods, Procedures, Process
During well-testing operations the produced hydrocarbon is usually flared in the open flare pit. As per the existing company's HSE procedures, flaring during well testing is considered as a safe option. However, flaring activities needs to be minimized or eliminated as some wells are located in environmentally sensitive areas which are close to farms, Highways or camping area. Due to location constraints the flaring should be minimized to the possible extent. As the well is exploratory, the well was not connected yet to the production facility. The only means of oil transportation will be by using road tankers, for that the H2S concentration in oil needs to be reduced to a permissible limit.
The heavy oil well to be tested contains H2S concentration upto 22 %(220,000 ppm) in gas. A novel process was initiated to eliminate/minimize flaring during well testing operations. H2S scavenger technology was selected for field trial to convert the produced sour liquid to be suitable for transportation through vacuum tankers to the nearest production facility. Accordingly H2S scavenger chemical was arranged and well test surface layout was modified with additional chemical dosing points. After separating the gas from oil using surge tank and separator dosed H2S Scavenger into oil line. This exercise resulted in ensuring that the H2S concentration in treated oil is at a permissible limit and the oil is suitable to be transported using road tankers.

Results, Observations, Conclusions
Field trail was implemented in sour heavy oil well to evaluate the feasibility of using H2S scavenger chemical to mitigate/minimize high H2S concentration in the produced fluid. Two heavy oil wells (17-200 API) were tested with this process and H2S content in oil was reduced to almost 15 ppm. Achieved economical H2S scavenger treatment cost of $18/bbl for reducing H2S in oil from 600 ppm to 15 ppm. Oil flaring was eliminated and only small quantity of the produced sour gas(0.001mmscfd) was flared safely through flare stack. Approximately 5,500 bbls of crude oil were produced from an exploratory well and safely transported by road tankers to nearby production facility during two weeks of testing period. For the first time in Kuwait an exploratory sour heavy oil well was successfully tested without flaring oil.

Novel/Additional Information
The innovative solution of using H2S Scavenger during testing the sour well had eliminated flaring of crude oil which avoided environmental pollution and conserved the produced oil. This success proves that sour heavy oil wells can be tested safely without flaring oil and paves the way for implementing this novel concept in future applications.
Modeling and Simultaneous History-Matching of Multiple WAG Coreflood Experiments at Reservoir Conditions
Authors: Duchenne S. , de Loubens R. , Petitfrere M. , Joubert T. 
Published: November 2015

Abstract
Good prediction of the performance of water-alternating-gas (WAG) processes relies on the proper estimation of three-phase relative permeabilities and their hysteresis with injection cycles. This is often a lengthy and expensive procedure requiring the numerical interpretation of several WAG corefloods, usually performed at reservoir conditions.
In this paper, we propose an automated procedure based on multi-experiment optimization, leading to a consistent set of three-phase hysteresis parameters for all available experimental data. We apply it to two near-miscible WAG coreflood experiments that differ in the number and length of their injection cycles (long slugs versus short slugs). Both experiments were performed at reservoir conditions on a horizontal sandstone core, with light oil from a West African field and below minimum miscibility pressure. These experiments were carried out using extensive monitoring, including material balance at standard and reservoir conditions, full compositional analysis of liquids and gas produced at standard conditions, differential pressure measurements across the core and three-phase in situ saturations using a dual energy X-ray scanner.
History-matching results were obtained by coupling our optimization tool with an in-house research reservoir simulator (IHRRS), combining an advanced EoS-based equilibrium relaxation model with a three-phase relative permeability hysteresis model. Optimization was performed with the Nelder-Mead algorithm, using a relatively large number (&gt;10) of fitting parameters to model the relative permeability functions and their hysteresis. Multiple sets of parameters were easily obtained to match each experiment individually, suggesting that the history-matching of a single experiment is poorly constrained. As expected, muti-experiment optimization led to a better constrained but more challenging problem to solve; yet all available data could be matched reasonably well with a common set of parameters and several acceptable solutions were found.
By providing a more robust estimation of three-phase hysteresis parameters, the proposed method increases the reliability of our simulation-based interpretations, necessary to evaluate the stakes of a WAG project.