bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimizing BHA's Through Comparison of Conventional Drilling Methods to Use of Rotary Steerable Systems in the Barnett Shale
Authors: Goldsmith Jessica 
Published: June 2014

Abstract
The well that discovered the Barnett Shale was drilled in 1981. However, due to the complexity of this formation and lack of technology, it was not economically possible to drill this field at the time. It was not until the late 1990's that technology became available which allowed for economically viable drilling to be completed. Since then, the Barnett Shale has exploded and is the second largest producing gas field in the US behind the Panhandle-Hugoton field. As of February 2010, 246 operators were listed as working in the Barnett Shale field with13,740 wells on RRC records with 3,273 permitted wells. With the large number of operators, wells and new challenges in the area, it has become critical to find the best possible methods for drilling economically.
In this paper, an operator's conventional method of directional drilling using a steerable motor is being compared to trials of directional drilling using a rotary steerable system. The area of focus is Johnson County in the Barnett Shale (Fig 1). The operator began drilling in Johnson County in 2003. Until a few years ago, directional drilling was primarily completed using a steerable mud motor with either a fixed or adjustable bent housing and MWD. Rotary steerable tools were first tested in 2007, however, the trials covered in this paper began in 2009. One hundred percent of the wells drilled by the operator are horizontal. The typical well was drilled with a lateral less than 5,000 feet long. As drilling progressed, longer laterals were required. Due to surface location restrictions on a group of wells to be drilled, the laterals reached lengths of 6,000-7,000 feet. These lengths were necessary to drill under an urban area where surface locations were not available to accommodate shorter laterals. Torque and drag analysis was conducted to decide if conventional methods could be used. It was determined that conventional methods could not be used because of the potential for the drill pipe to buckle at the base of the curve and that rotary steerable tools must be used.
Reactivation Project
Authors: Borkhoche Roy 
Published: June 2014

Abstract
The reactivation project is a selection process to assess the value of inactive wells for the purpose of qualifying them or not as reactivation candidates. Engineering and economic criteria are incorporated into the selection process. The inactive wells studied belong to mature hydrocarbon fields located in West Texas. Primary field development dates to the early 20th century. Since then, infill drilling and various enhanced-oil recovery projects have been performed. Identification of reactivation candidates is important to realize the full potential of mature producing fields and to recover potentially bypassed pay. From a data set of 200 wells two reactivation candidates (wells A and B) were selected. The purpose of the paper will describe the selection process and focus on the well reactivation.
Several factors limit the recovery ratio from a given well. As the global demand for energy grows, petroleum companies will focus on the exploration and production of new hydrocarbon reserves. In the process of shifting resources from existing to newly-found fields, companies may neglect to realize the full potential of mature fields. Furthermore, engineering practices and tools of the past contribute to undermining recoverable reserves from a given reservoir. Advances in technology have led to improved field development strategies and optimum well recovery. Reactivation project applies current technologies for identifying and unlocking potential in inactive wells.
Based on the reactivation study, both wells A and B promise to increase reserves and add value. Well A is estimated to add recoverable reserves of 37 thousand bbl of oil and 372 MMcf of gas. Moreover, there is a contingency plan for well A. If reactivation of the lower zone is prevented by a major casing failure, then a shallow recompletion is proposed. The shallow zone is estimated to hold 534 MMcf of recoverable gas. On the other hand, well B evaluation indicates recoverable reserves of 30 thousand bbl oil and 89 MMcf gas. The two reactivations have a maximum potential of 145 thousand BOE and an associated net present value (NPV) of $1.92 million (reserve and NPV values do not include well A contingency plan).
Formation Damage Caused by Improper Mn3O4-Based Filter-Cake-Cleanup Treatments
Authors: Al Moajil Abdullah M. , Nasr-El-Din Hisham A. 
Published: June 2014

Summary
Cleanup of filter cake is a difficult task and becomes more challenging when dealing with weighting materials [e.g., manganese tetraoxide (Mn3O4)]. Mn3O4 is a strong oxidizing agent and can be used as a catalyst because of its active phase, a nonstoichiometric Mn3O4 composed of an octahedral Mn2O3 phase and a tetrahedral MnO phase, which will result in complex interactions with most cleaning fluids. The reaction of selected organic acids and chelating agents with Mn3O4 particles as a function of time and temperature was studied. Solubility and compatibility tests of Mn3O4 particles with cleaning fluids were conducted using a high-pressure/hightemperature (HP/HT) see-through cell. Reaction kinetic tests were conducted using a three-neck round-bottom flask. Atomic absorption was used to measure manganese concentration, and X-ray diffraction was used to analyze solids remaining after the reaction. A white precipitate of manganese citrate was produced following the reaction of citric acid with Mn3O4 up to 284°F. The amount of precipitate was increased with temperature and initial acid concentration. An amino polycarboxylic acid chelating agent derived from L-glutamic acid (GLDA) (a chelant) reacted with Mn3O4 particles completely at 190°F. However, a large amount of a white was precipitate produced. Similarly, a white precipitate was observed with oxalic and tartaric acids. The reaction of diethylene triamine pentaacetic acide (DTPA) (a chelate) with Mn3O4 particles in a glass reactor produced Mn (silicates) at 212 and 284°F. The results of the present study will help drilling/completion engineers avoid using such cleaning fluids to prevent formation damage after filter-cake-removal treatments.
The Petrophysics of Problematic Reservoirs
Authors: Worthington Paul F. 
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.
Introduction
Petrophysics provides the building blocks for integrated reservoir models. It encompasses the analysis of well logs run on wireline and drillstring, conventional and special core analysis, mud logging, and formation testing and fluid sampling. The subject has open- and cased-hole cultures. For deviated and horizontal wells, and/or in the presence of dipping beds, petrophysical analysis is 3D and it should account for formation anisotropy, particularly transverse/ longitudinal differences in rock properties where reference directions are relative to bedding. To manage the current task, the discussion notionally refers to water-wet reservoirs sensed by openhole well logs, although there are exceptions where the reservoir also is the source. Beyond this, the subject matter has been selected on the basis of topicality.
Petrophysical Evaluation
Most commonly, petrophysics is concerned with the technical evaluation of laboratory data and downhole measurements for reservoir properties such as shale-volume fraction Vsh, porosity f, permeability k, net/gross reservoir, water saturation Sw, and net/gross pay. The subject has a philosophy of indirectness, in that, often, it is not possible to measure a required reservoir property directly. Therefore, it is necessary to measure some other property that is related to the required property. For this reason, petrophysics is built around a framework of interpretive algorithms that relate measurable parameters to reservoir parameters. Usually, these algorithms are empirical with some conceptual reference. This means that quantitative petrophysical interpretation is, mostly, data driven and that the interpretive algorithms change from reservoir to reservoir. This, in turn, requires that each reservoir be investigated separately and thoroughly. For general formation evaluation, see Warner and Woodhouse (2007); for net-pay evaluation, see Worthington (2010a).
Archie Reservoirs. Petrophysical interpretive procedures usually are described in terms of an idealized clastic reservoir, which is the textbook reference and is sometimes termed an ’Archie?? reservoir because it broadly matches the requirements for the application of the fundamental Archie equations that provide the quantitative basis for welllog analysis (Archie 1942). Attributes of an Archie reservoir are listed in Table 1. Although these conditions were not itemized explicitly by Archie (1942), they are implicit in the use of the Archie equations on the basis of many years of application.
Don't Drop the Anchor: Recognizing and Mitigating Human Factors When Making Assessment Judgments Under Uncertainty
Authors: Sykes M. A. , Welsh M. B , Begg S. H 
Published: June 2014

Abstract
One of the most important tasks a petroleum geologist undertakes is to recognize and incorporate uncertainty concepts into their geologic interpretations and estimates of volumetric parameters. This is crucial, because the first requirement for sound decision-making is an accurate and unbiased evaluation of uncertainty in hydrocarbon volume estimations. Reducing uncertainty is a worthy, but secondary, objective. However, not only is the information upon which geologists make such judgments imperfect, incomplete and potentially biased, but the pernicious effects of certain human factors can amplify bias and create unrealistically narrow ranges.
A wide variety of human factors which influence such judgments have been revealed over recent years by applying psychological research techniques to geologic interpretation issues. Two of the most powerful and damaging cognitive effects are anchoring and overconfidence (Tversky & Kahneman, 1974).
Anchoring refers to the tendency for one piece of information, such as a "base case", to inappropriately constrain estimates. Overconfidence is the tendency to estimate ranges that are systematically too narrow with respect to the state of knowledge. Together, these result in inappropriately precise predictions of hydrocarbon volumes ranges, with a concomitant degradation in accuracy. The phenomena are found to be powerfully ingrained, even in the minds of experts (Morgan & Henrion, 1990; Northcraft & Neale, 1987; Welsh, Bratvold, & Begg, 2005), who frequently have a disproportionately large influence on the final estimates.
This paper describes and reports observations from both a program that ExxonMobil, with the Australian School of Petroleum, has embarked upon to increase awareness of these biases, and to develop tools to help mitigate their effects; and observations from the oil and gas industry as a whole. The ExxonMobil program is implemented through formal training and informal mentoring. Geologists are provided with exercises to test their natural predilection towards overconfidence, and susceptibility to being anchored. Upon revealing the influence of the bias, it is intended that the individuals take away an internalized caution against falling victim to these subtle traps in their future interpretations.
The durability of such learning is not necessarily permanent, however, and frequent reminders of the phenomena are imparted in order to reinforce and refresh. This is intended to inculcate mitigative behaviors in the members of the geological community over the long term.
Demonstrating Reasonable Certainty Under Principles-Based Oil and Gas Reserves Regulations
Authors: Sidle R.E.. E. , John Lee W.. 
Published: June 2014

SummaryHistorically, oil and gas reserves definitions have included the term "reasonable certainty" when describing the standard of high confidence/low uncertainty for a conservative estimate of future recovery from an accumulation. In 2008, the US Securities and Exchange Commission (SEC), one source for such definitions and regulations, changed its rules on oil and gas reserves and moved from a more rules-based approach to a more principles-based approach. While the SEC regulations both before and after this change incorporated the term "reasonable certainty," the philosophical change from rules-based to principles-based regulation puts more responsibility on the reserves evaluator to understand the uncertainties in the reserves estimation and to "get it right."This paper examines the stated definition of reasonable certainty as well as the effective definition based on how the regulations were interpreted under the prior rules-based system. Examples of prior methods of regulatory controls, under a rules-based system, that no longer fit under a principles-based system are noted. The paper then examines the current definition. The overprint of a principles-based regulatory system must be considered to understand how such an approach will impact the effective definition under the current rules. The insights from the financial and legal communities are examined for their learnings in which other forms of regulations underwent this same philosophical change. This examination describes how rules-based systems are more "input control" focused, while principles-based systems focus more on "outcomes."Next, the paper suggests how the reserves evaluator should apply this understanding of the new principles-based rules. The evaluator is now more responsible to understand the range of uncertainty in reserves estimates and to ensure that the outcome (the proved reserves estimate) satisfies the regulations. Also, the paper discusses key tests to demonstrate that the correct outcome— a reasonably certain volume—has been achieved. After 30 years of well-established practices, the responsible reserves evaluator has examined changes as they evolved in then-current regulation text. Now, the evaluator needs to additionally consider changes based on the implications of principles-based regulations.
A Comparative Study of Transient and Steady-State Three-Phase Oil Permeability
Authors: Dehghanpour Hassan , DiCarlo David A. 
Published: June 2014

SummaryRelative permeabilities for three-phase flow are commonly predicted from two-phase-flow measurements using empirical models. These empirical models are usually tested against available steady-state data. However, the oil flow is transient during various production stages [e.g., gas injection after waterflood and steamassisted gravity drainage (SAGD)]. Hence, there is a need to test the empirical models against unsteady-state or transient data. We compare two sets of three-phase oil-permeability data measured during tertiary gasflood. The first data set, which was recently published (Dehghanpour et al. 2011a), is measured during transient gravity-drainage experiments, and will be detailed further here. The second set was measured by Oak et al. (1990) during steady-state corefloods. We compare the two data sets with the corresponding two-phase permeability curves, and observe different qualitative behaviours. The comparison indicates that during steady-state tertiary gasflood, the presence and flow of water restrict the oil flow, while during transient tertiary gasflood, water-saturation drop enhances the oil flow. We test the performance of well-known empirical models further in predicting the two data sets, and explain how Stone I and saturation-weighted interpolation (SWI) should be used to usefully predict oil permeability during a three-phase tertiary displacement.
A Parametric Simulation Study for Solvent-Coinjection Process in Bitumen Deposits
Authors: Yazdani Ali , Alvestad Jostein , Kjoensvik Dagrun , Gilje Eimund , Kowalewski Espen 
Published: June 2014

Summary
In-situ extraction of ultraviscous deposits from the vast bitumen resources in western Alberta, Canada, requires significant water and energy usage, which consequently leads to greenhouse-gas emissions. Currently proven steam-based recovery schemes include cyclic-steam-stimulation (CSS), steamflooding, and steam-assisted gravity-drainage (SAGD) processes, which are accompanied by many economic and environmental challenges. Coinjection of solvent with steam is a technology that has the potential to improve the efficiency of steam processes as well as reduce energy usage and carbon dioxide emissions.
In recent years, researchers and industry professionals have attempted to develop the process further by conducting fundamental research as well as field pilot trials, with varying degrees of success. However, the current level of understanding of the process and the knowledge surrounding the fundamental physics and mechanisms involved are not entirely satisfactory.
In this paper, a parametric simulation study was performed to address the key aspects of the solvent-coinjection (SCI) process that contribute to further understanding and development of the process. Simulation observations were verified with experimental evidence where available to support the results and conclusions. Effects of several operational and geological parameters were evaluated on the performance of the SCI process, and the relative performance benefits were assessed over normal SAGD operations. These parameters included solvent type, solvent concentration, initial-solution gas/oil ratio (GOR), relative permeability curves, and pay thickness.
The results revealed that the optimal solvent should not be chosen only on the basis of mobility-improvement capability, but also under consideration of other operational, phase- and flow-behavioral and/or geological conditions that are set or present. Higher concentrations of solvents showed more energy-saving upsides than rate-acceleration benefits. It was also observed that the reservoir steam-intake rate is still likely to be the prime performance indicator of the SCI process. In addition, SCI showed that the potential exists for accessing more resources, particularly below the producer level. Furthermore, steam trap control on the producer seems to be problematic when used for SCI simulation. With the current well-control capacity of simulators, a higher degree of subcool is likely to be needed to avoid live vapor-phase production from the producer.
Design of Solvent-Assisted SAGD Processes in Heterogeneous Reservoirs Using Hybrid Optimization Techniques
Authors: Al-Gosayir Muhammad , Leung Juliana , Babadagli Tayfun 
Published: June 2014

Summary
Numerous steam-assisted gravity-drainage (SAGD) optimization studies published in the literature combined numerical simulation with graphical or analytical techniques for design and performance evaluation. Efforts have integrated the simulation exercise with global optimization algorithms. Some studies focused on optimization of cumulative steam/oil ratio (cSOR) in SAGD by altering steam-injection rates, while others focused on optimization of net cumulative energy/oil ratio (cEOR) in solvent-additive SAGD by altering injection pressures and fraction of solvent in the injection stream. Several studies also considered total project net-present-value (NPV) calculation by changing total project area, capital-cost intensities, solvent prices, and risk factors to determine the well spacing and drilling schedule. Optimization techniques commonly used in those studies were scattered search, simulated annealing, and genetic algorithm (GA). However, applications of hybrid GA were rarely found.
In this paper, we focused on optimization of solvent-assisted SAGD using various GA implementations. In our models, hexane was selected to be coinjected with steam. The objective function, defined on the basis of cSOR and recovery factor, was optimized by changing injection pressures, production pressures, and injected solvent/steam ratio. Techniques, including orthogonal arrays (OA) for experimental design (e.g., Taguchi's arrays) and proxy models for objective-function (F) evaluations, were incorporated with the GA method to improve computational and convergence efficiency. Results from these hybrid approaches revealed that an optimized solution could be achieved with less central-processing-unit time (e.g., fewer number of iterations) compared with the conventional GA method. Sensitivity analysis was also conducted on the choice of proxy model to study the robustness of the proposed methods.
To investigate the effects of heterogeneity in the design process, optimization of solvent-assisted SAGD was performed on various synthetic heterogeneous reservoir models of porosity, permeability, and shale distributions. Our results highlight the potential application of the proposed techniques in other solvent-enhanced heavy-oil-recovery processes.
Solvent-Chamber Development in 3D-Physical-Model Experiments of Solvent-Vapour Extraction (SVX) Processes With Various Permeabilities and Solvent-Vapour Qualities
Authors: Knorr Kelvin D , Imran Muhammad 
Published: June 2014

Summary
Solvent-vapour extraction (SVX) processes offer an attractive alternative to thermal recovery processes by being less energy intensive and are more suitable for thinner, partially depleted reservoirs. A typical SVX process uses solvent injection to dilute the heavy oil by reducing its viscosity, allowing it to be mobilized for production. During this process, the injection of hydrocarbon solvents results in partial deasphalting of the heavy oil, thus reducing its viscosity and enhancing the process performance further.
This work examined the formation and growth of solvent chambers in laterally and vertically spaced horizontal injector/producer well pairs in porous media with five different permeabilities and three different solvent-vapour qualities. Consolidation of the porous media caused by asphaltene precipitation was also analyzed. Thermal-imaging and model excavation studies were performed to investigate the formation and growth of solvent chambers for seven different experiments conducted on a large 3D-physical-model apparatus.
The important findings from this study are as follows: During solvent injection, one or more solvent fingers develop between the injector and producer. The dominant solvent finger becomes a conduit that grows into a solvent chamber connected to the injection well in the upper portion of the reservoir, and develops into an oil-drainage conduit connected to the production well in the lower portion of the reservoir. Solvent dispersion layers are located on the margins of both the solvent chambers and the oil-drainage conduits. The location and development of these nonuniform solvent chambers and oil-drainage conduits are unpredictable, and the oil-drainage conduits do not grow significantly in diameter once connected to the production wellbore, limiting the wellbore inflow efficiency and conformity. Asphaltene precipitation and migration can aggravate this inflow problem, reducing the SVX process performance further.
SVX performance can be improved by increasing the number and diameter of oil-drainage connections between the solvent chamber and the production well, and by controlling the oil deasphalting process. This can be performed by optimizing injection- and production-wellbore geometries, and by optimizing solvent-injection rates and vapour quality.