bluuebunny/crossref_metadata_2025_split huggingface dataset:
Impact of Material Balance Equation Selection on Rate-Transient Analysis of Shale Gas
Authors: Williams-Kovacs J. D. , Clarkson C. R. , Nobakht M. 
Published: October 2012

Abstract
Various forms of shale gas (SG) material balance equations (MBE) have been developed in the past several decades, dating back to the first round of coalbed methane (CBM)/SG development in North America. These equations attempt to incorporate various aspects of SG storage mechanisms and reservoir characteristics; simple to complex forms exist, depending on the number of assumptions made in their derivation. All of the equations account for adsorbed gas storage, but may or may not include corrections for pore volume (PV) and fluid compressibility, water influx etc. In higher-permeability fractured SG and CBM plays, application of material balance using static (shut-in) pressures to derive original gas-in-place (OGIP) and drainage area estimates has proven useful. With the current development of ultra-low permeability SG (and shale liquids) plays, shut-in times for wells is impractically long so as to preclude the use of static material balance (SMB) methods. Use of rate-transient analysis (RTA) techniques, such as the flowing material balance (FMB), is much more common for original gas-in-place (OGIP) derivations in ultra-low permeability reservoirs, yet some form of MBE is often required for application of these methods. For example, pseudo-time and material balance pseudo-time is commonly used in advanced RTA methods, and hence the form of MBE could impact reservoir and/or hydraulic fracture properties derived from the analysis.
In this work, we first summarize the MBEs that have been derived specifically for SG and/or CBM, with an emphasis on the assumptions, limitations and applications of each equation. We then derive a new MBE that dynamically adjusts free-gas storage volume during depletion according to the amount of volume occupied by sorbed gas, as recently suggested by Ambrose et al. (2010) for volumetric gas-in-place determination. Finally, we examine the impact of MBE selection on quantitative rate-transient analysis (for estimation OGIP). Two simulated cases for SG reservoirs are used to demonstrate the impact of the selected MBE. Finally, a modified transient productivity index (PI) using average pressure in the region of influence was developed and is compared to conventional transient PI. The results of this study are of interest to those engineers performing unconventional reservoir characterization work using RTA and for reserves estimators.
Characterization of Critical Fluid, Rock, and Rock-Fluid Properties-Impact on Reservoir Performance of Liquid-rich Shales
Authors: Honarpour M. M. , Nagarajan N. R. , Orangi A. , Arasteh F. , Yao Z. 
Published: October 2012

Abstract
Liquid-rich Shale (LRS) reservoirs are economically attractive but operationally challenging. Fluid, rock, and rock-fluid properties are critical for optimal reservoir development and management. Formation heterogeneity, fluid variability, and complexity of rock-fluid properties render fluid flow characterization a challenging task. Additional challenges associated with coring, fluid sampling and analysis include the recovery of quality cores and representative fluid samples, and timely acquisition of high quality data for making critical engineering design decisions.
Rock and fluid analyses should be done in the following stages so that the critical data become available in a timely manner for making key decisions:
a) ‘Wellsite Analysis’ including mineralogy/total organic content, TOC; b) ‘Quick Look laboratory analysis’ for detailed mineralogy and basic petrophysical properties; c) ‘Fast Track’ geomechanical, geochemical properties and petrophysical analysis on core plugs; and d) ‘Full Suite’ rock-fluid analysis for integrated studies.
Low formation permeability, long transients, and contamination with OBM and fracturing fluid make acquisition of representative downhole or early surface fluid samples impractical. An alternative approach is to integrate mud gas analysis with light and heavy end components extracted from full diameter cores in canisters to reconstruct in-situ fluids. The PVT modeling should account for the impact of high capillary pressures encountered in unconventional shale reservoirs for reliable reservoir performance prediction.
This paper presents the best practice methodology for characterizing critical rock and fluid properties, their variability and their impact on performance through parametric simulation studies. A sector model was constructed consisting of alternate TOC- and calcite-rich layers with a horizontal well placed in a calcite-rich layer. A network of hydraulic and natural fractures was implemented in the model to study the sensitivities to fluid and rock properties, relative permeability, capillary pressure, and fracture properties. It was found that the critical rock and fluid data impacting the initial rate and ultimate recovery were effective permeability, its anisotropy, its alignment with hydraulic and natural fracture network, rock-type based compaction, unconventional PVT behavior such as decreased oil bubble point pressure and the resultant viscosity and GOR behavior, interfacial tension (IFT)/capillary pressure, and relative permeability.
The Effect of Water-Induced Stress to Enhance Hydrocarbon Recovery in Shale Reservoirs
Authors: Fakcharoenphol Perapon , Charoenwongsa Sarinya , Kazemi Hossein , Wu Yu-Shu 
Published: October 2012

Abstract
Waterflooding has been an effective improved oil recovery process for several decades. However, stress induced by waterflooding has not been well studied or documented. Water injection typically increases reservoir pressure and decreases reservoir temperature. The increase in reservoir pressure and decrease in reservoir temperature synergistically reduce the effective stress. Because of such decrease in stress, existing healed natural fractures could be reactivated and/or new fractures could be created. Similar effects could enhance hydrocarbon recovery in shale reservoirs.
In this paper, we calculated the magnitude of water injection-induced stress using a coupled flow-geomechanics model. To evaluate the effect of water injection in the Bakken, a numerical simulation study for a sector model was carried out. Stress changes due to the volume created by the hydraulic fracture, water injection, and oil production were calculated. Hoek-Brown failure criterion was used to compute rock failure potential.
Our numerical results for a waterflooding example show that during water injection, the synergistic effects of reservoir cooling and pore-pressure increase significantly promotes rock failure, potentially reactivating healed natural macrofractures and/or creating new macrofractures, especially near an injector. The rock cooling can create small microfractures on the surface of the matrix blocks. In shale oil reservoirs, the numerical experiments indicate that stress changes during water injection can improve oil recovery by opening some of the old macrofractures and creating new small microfractures on the surface of the matrix blocks to promote shallow water invasion into the rock matrix. Furthermore, the new microfractures provide additional interface area between macrofractures and matrix to improve oil drainage when using surfactant and CO2 EOR techniques. These positive effects are particularly important farther away from the immediate vicinity of the hydraulic fracture where much of the undrained oil resides.
Dynamic UnderBalance perforations bring higher productivities than conventional perforations: a large scale comparative review from the Tunu Gas Field (Indonesia)
Authors: Perrier Sebastien , Sugiarto Tomi 
Published: October 2012

Abstract
Tunu is a multilayered gas field operated by Total EP Indonesie in the Kutei basin, which has produced 8Tcf since 1993. It consists of thousands of gas-bearing sandstone reservoirs, spread over up to 2000m of vertical gross thickness, developed using tubingless completions (more than 700 wells to date). Perforations are performed by light electric unit swamp barges, following a progressive bottom-up strategy.
Perforation techniques applied in the field typically involve perforating in static under-balanced pressure conditions with conventional guns and charges (underbalance value and gun design may vary). However, more than 40 reservoirs were perforated using Dynamic Underbalance technologies between 2005 and 2011.
This paper presents an in-depth comparative survey of the performance of these 2 perforation techniques, and compares the productivity obtained from these jobs to an extensive benchmark of documented conventional perforations.
Methodologically, all reservoir and perforation parameters influencing perforation performance are reviewed, to search for, and correct, any possible statistical bias in the comparison of different groups of reservoirs. Using methods classically used in epidemiological statistics, the aim is to get a statistically sound comparative survey on the productivity provided by these two techniques of perforation.
Based on two independent methods, this paper shows that the Dynamic Underbalance technique provides reservoir productivities significantly better than conventional perforations in gas reservoirs. The robust statistical confidence associated to this productivity increase will be explicitly discussed and presented in this paper.
Transient Pressure Test Interpretation for Continuously and Discretely Fractured Reservoirs
Authors: Kuchuk Fikri , Biryukov Denis 
Published: October 2012

Abstract
Fractures are common features of many well-known reservoirs. Naturally fractured reservoirs consist of fractures in igneous, metamorphic, and sedimentary rocks (matrix) and formations. Faults in many naturally fractured carbonate reservoirs often have high permeability zones, and are connected to many fractures with varying conductivities. Furthermore, in many naturally fractured reservoirs, faults and fractures can be discrete (i.e., not a connected-network fracture system). To understand the pressure behavior of these continuously and discretely fractured reservoirs, semianalytical solutions are presented. These solutions are used for transient well test interpretation of formations containing a network of discrete and/or connected (continuous) finite- and infinite-conductivity fractures. In this paper we present an extensive literature review of the pressure transient behavior of fractured reservoirs. First, we show that the Warren and Root (1963) dual-porosity model is a fictitious homogenous porous medium because it does not contain any fractures. Second, using the new solutions, we show that for most naturally fractured reservoirs the Warren and Root (1963) dual-porosity model is inappropriate and fundamentally incomplete for the interpretation of pressure transient well tests because it does not capture the behavior of these reservoirs.
We examined many field well tests published in the literature. With few exceptions, none of them shows the behavior of the Warren and Root (1963) dual-porosity model. These examples exhibit the very rich pressure behavior of discretely and continuously fractured reservoirs. Unlike the single derivative shape of the Warren and Root (1963) model, the derivatives of these examples exhibit many different flow regimes depending on fracture distribution, and on their intensity and conductivity. We show these flow regimes using our new model for discretely and continuously fractured reservoirs. These derivatives will be a valuable diagnostic tool for well test interpretation. Most well tests published in the literature do not exhibit the Warren and Root (1963) dual-porosity reservoir model behavior. If we interpret them this dual-porosity model, then the estimated permeability, skin factor, interporosity flow coefficient (λ), and storativity ratio (ω) will not represent the actual reservoir parameters.
Real-Time Prediction Ahead of the Bit in an Exploration Well in the Cordillera Basin, Colombia
Authors: Duque Helman , Ramirez Carlos Andres , Quinn Dan , Rodriguez Yerayen , Jaramillo Jose Arturo , Ruiz Juan Camilo 
Published: October 2012

Abstract
New areas of oil exploration in Colombia are usually located in complex geological settings where conventional surface seismic data is traditionally of poor resolution. The recent improvements in borehole seismic software applications has made it possible for real-time vertical seismic profile (VSP) processing at wellsite to provide time-critical information with improved vertical resolution. This advancement has promoted the use of VSP applications in complex areas, as is the case of the zero-offset vertical seismic profile (ZVSP) data that was acquired in an exploration well in the Cordillera basin of Colombia. The real-time results obtained by processing the VSP data at the wellsite shortened the decision-making process (reduced NPT); in this case, it aided in the decision to invest additional resources to continue to drill a reflector observed on the VSP below the initial target. This case history describes the real-time wellsite application of acoustic impedance inversion of the upgoing waves and prediction ahead of the bit. In this example, the new target was encountered 5 ft below the prediction. The acquisition and processing of this data reduced uncertainties and verified the new target below the bit.
The results of the theoretical model and the actual data demonstrate that the method is effective for pre-drilling predictions using borehole seismic data; these results also make the VSP a powerful tool for making decisions during the drilling stage of the project. This paper describes the acquisition, processing, and method used to help improve subsurface imaging and to predict the depth to the reflectors ahead of the bit.
Application of CFD to Debottleneck Production Separators in a Major Oil Field in the Middle East
Authors: Kharoua Nabil , Khezzar Lyes , Saadawi Hisham 
Published: October 2012

Abstract
In order to debottleneck very large three phase production separators in a Middle Eastern oil field, new high efficiency internals were installed. A Computational Fluid Dynamics (CFD) study was conducted of these three-phase separators. The study focused on the evaluation of internal modifications and the influence of the inflow characteristics. A combination of the Eulerian-Eulerian multiphase and k-ε turbulence models was used to simulate the complex behavior of the flow inside the separator. A series of parametric case studies was conducted. The findings of the CFD study were compared with the results of field performance test.
This paper describes the approach adopted in the CFD study. The geometry, mesh, numerical models, simulation strategy as well as the results and findings are discussed in detail.
An Examination of Cultural Values and Employees' Perceptions of Support on Affective Reaction and the Desire to Participate in a Formal Mentoring Program in an OilField Services Corporation
Authors: Hayes Hanna Bea , Rousseau Meta 
Published: October 2012

Abstract
Many researchers have examined the effect of formal mentoring on job satisfaction and organizational commitment. However, there has been little or no focus on an employee's intent to participate in a formal mentoring program based upon an employee's perceived organizational support, and/or affective reaction (job satisfaction and organizational commitment). In the current study, the researcher examined the relationship among cultural values, perceived organizational support (career and psychosocial support), affective reaction (job satisfaction and organizational commitment), and the intent to participate in a formal mentoring program in an oilfield services organization. A 44-item electronic survey was utilized to collect data. The questionnaire was sent to 831 Field Engineers 1 (FEl's) in forty-two countries within an oilfield services organization. The sample included 341 respondents. Descriptive statistics, Cronbach's alpha estimates for reliability, factor analysis, correlation analysis, regression analysis, path analysis, and structural equation modeling were the analyses used in the study.
The researcher posited that cultural values amongst the FEls do not differ significantly; moreover, the cultural values do not influence the FEls perceived organization support. Further, it was found that FEl's perceived support (career and psychosocial) and affective reactions predicted the FEl's intent to participate in a formal mentoring program.
Advanced Completion and Fracturing Techniques in Tight Oil Reservoirs in Ordos Basin: A Workflow to Maximize Well Potential
Authors: Liu Hai , Luo Yin , Li Xianwen , Xu Yonggao , Yang Kewen , Mu Lijun , Zhao Wen , Zhou Shuxun 
Published: October 2012

Abstract
In recent years, great efforts have been focused on tight oil reservoirs in Ordos Basin, which is located in North Central China. Although historical field development in these tight oil reservoirs was still economical, average production after hydraulic fracturing is quite low and most of wells produce just at the margins. In order to understand production potential through appropriate completion and fracturing techniques, a pilot project was initiated recently on two horizontal wells drilled in parallel, with three vertical wells placed between two horizontal wells along the lateral for real time fracturing monitoring.
This paper describes how the treatment design was optimized based on detailed formation evaluation and fracture simulation using a 3D unconventional fracturing design workflow. It presents real time fracture mapping results through a dual monitoring well setup on total 26 stages of fracturing treatments, and also illustrates how the results were utilized to adjust and optimize treatment design during and between treatment stages. The paper demonstrates the application of a unique Unconventional Fracture Model (UFM) that was developed for design and evaluation hydraulic fracturing treatment in unconventional reservoirs. The model incorporates predefined natural fracture patterns and interaction criteria for hydraulic and natural fractures. The paper also discusses the outcome of simultaneous treatments tested in four stages compared to other stages pumped in sequences.
Initial production tests on both wells show 124.5 m3/d and 103.2 m3/d respectively, which are significantly higher than all the wells completed in tight oil reservoirs in the basin, of which the production varies from 5-8 m3/d in vertical wells to 32 m3/d in horizontal wells on average. In-depth reservoir understanding, advanced design and evaluation workflow, and appropriate completion and fracturing technique are the key of this success, which has set a milestone for developing such tight oil reservoirs in Ordos Basin.
Strategic Baseline Groundwater Sampling for Shale Exploration
Authors: Leatherbury Ryan , Denson Barbara Brandl 
Published: October 2012

Abstract
Exploration and production from unconventional shale resources has increased significantly in the past several years due to the success of combining horizontal drilling and hydraulic fracturing technologies in a manner that allows natural gas and/or oil to be released from relatively impermeable shale formations. The rapid increase in shale development has raised the concern of landowners and the public that the use of these techniques could adversely impact the groundwater resources in and around the development. In general, there is a lack of real data documenting pre-drill and post-drill conditions that could be used to truly evaluate the impacts of shale development. Using a technically sound strategy to collect data is important in an effort to document baseline environmental and, in particular, groundwater conditions prior to exploration so that post drilling conditions can be evaluated when necessary. The collection of scientifically defensible data for operators involved in the development of a shale play improves stakeholder engagement, protects operators from potential environmental degradation claims, and allows for science-based regulation that truly protects the resources. Collecting a representative set of samples from groundwater supply wells within a defined radius of a well pad prior to drilling activities provides the operator with information that documents pre-drilling groundwater conditions. Performing this type of baseline sampling within a well-designed, scientifically and legally defensible program can help the operator manage and mitigate corporate risk. The public concern over impacts to groundwater must be taken seriously, and adhering to a well designed program that produces science-based results will increase public confidence in the industry's operating practices. This paper presents baseline groundwater sampling program rationale and design based upon existing regulations and experience gained in the United States shale exploration regions.
Challenges of Heavy Oil Fluid Sampling and Characterization
Authors: Nagarajan N. R. , Dong C. , Mullins O. C. , Honarpour M. M. 
Published: October 2012

Abstract
A significant portion of the world's hydrocarbon reserves is found in heavy oil reservoirs. Heavy oils are often found in shallow and highly unconsolidated reservoirs, or sometimes in deep, tight formations. Often the high asphaltic content of these oils results in relatively higher oil density and viscosity; hence, their lower reservoir mobility poses significant challenges to both sampling and PVT data measurements. Furthermore, modeling these fluids for reservoir evaluation requires special techniques to capture their unique phase behavior.
The challenges of representative down-hole or surface fluid sample acquisition demand customized sampling methods to deal with:
low oil mobility sand production from unconsolidated formations high asphaltene content and resulting high gradients formation of water-in-oil emulsion during co-production of water or gas lift operations or addition of diluents
In addition, the prerequisite for laboratory measurement is special sample preparation to remove emulsified water. These high viscosity oils exhibit slower gas liberation below the bubble point and hence delayed gas-phase formation, thus making "true" oil property measurements a challenge. Difficulties associated with fluid modeling include characterizing apparent bubble point behavior, large viscosity changes with pressure and temperature, and asphaltene dropout.
In this paper, we present a comprehensive methodology for heavy oil sampling and characterization in unconsolidated sands as well as in low permeability reservoirs. We present field examples to highlight the challenges and illustrate the methodology for fluid sampling, down-hole fluid analysis, laboratory PVT data acquisition, and modeling. Sampling methods for heavy and asphaltic oils were custom designed with special tools and sensors to obtain representative samples and precise down-hole fluid analysis data. New laboratory techniques were developed to prepare the samples for analysis and to distinguish between the "true" and "apparent" bubble point behavior exhibited by the heavy oil due to its non-equilibrium behavior. Fluid models based on a special equations of state (EoS) were employed for accurate description of heavy oil fluid phase behavior. In particular, we successfully applied the industry's first EoS for asphaltene gradients in heavy oil reservoirs that match down-hole fluid data.