bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Electrodeless System for Measuring Electric Logging Parameters on Cores and Mud Samples
Authors: Fatt Irving 
Published: June 2014

Introduction
A recently developed system for measuring electrical resistivity of liquids without use of electrodes offers some interesting possibilities in electric logging technology. The equipment as supplied by the manufacturer is satisfactory for continuous mud logging on a drilling rig or for measuring mud or filtrate resistivity in the laboratory. A simple modification of the commercially available instrument makes it suitable for measuring resistivity of core samples in the laboratory.
The continuous measurement of mud resistivity on a drilling rig is a convenient means for detecting mixing of formation water with the drilling mud. Such information is useful to the geologist, the mud engineer and the logging engineer. However, continuous mud resistivity logging by conventional electrode-type resistivity cells is beset with difficulties. The mud, sand and rock chips abrade the electrodes, thereby changing the cell constant and eventually destroying the cell. Also, additives and crude oil in the mud may poison the electrodes by coating them with a nonconductive material. An electrode-type resistivity cell, therefore, may give erroneous readings under certain conditions. Electric logging companies circumvent the electrode poisoning problem by using a four-electrode resistivity cell for measurement of mud resistivity. In this cell, change in electrode area does not change the cell constant. However, the four-electrode cell is difficult to adapt for continuous reading and does not solve completely the problem of electrode abrasion by the sand and cuttings in the mud.
The measurement of electric logging parameters on core samples in the laboratory encounters some of the same problems discussed in connection with mud logging. Ideally, the electrical resistivity of a core sample should be measured by placing platinum black electrodes in direct contact with the plane ends of a cylindrical or rectangular sample. Platinum black electrodes however, are much too fragile and easily abraded to be brought in contact with a rock sample. Also, oil or other constituents in the fluid contained in the sample will poison platinum black. In practice, gold-plated brass electrodes, in an AC bridge circuit operating at about 1,000 cps, are used for routine core analysis. For more precise work in research studies, a four-electrode scheme is used. Preparation of the samples for the four-electrode method is much too involved for routine core analysis.
Jumps in Proved Unconventional Gas Reserves Present Challenges to Reserves Auditing
Authors: Weijermars Ruud 
Published: June 2014

SummaryThis study analyzes the typical challenges and opportunities related to unconventional-gas-reserves maturation and asset performance. Volatility in natural-gas prices may lead to downgrading of formerly proved reserves when the marginal cost of production cannot be sustained by the wellhead prices realized. New US Security and Exchange Commission (SEC) rules have accelerated the growth of unconventional-gas reserves, which in a way is an additional but unintended source of volatility and hence risk. Concerns about security of investments in unconventional-gas assets are fuelled by the effects of volatile natural-gas prices on production economics and by uncertainty about stability of reported reserves. This concern is exacerbated by an unprecedented rise in proved undeveloped gas reserves (PUDs) reported by unconventional-gas operators, arguably effectuated by favorable interpretations of PUDs when applying the new SEC accounting rules. This study includes a benchmark of proved reserves reported by two peer groups, each comprising four representative companies. The peer group of conventional companies includes Exxon, Chevron, Shell, and BP, and the unconventional peer group is made up of Chesapeake, Petrohawk, Devon, and EOG. Possible sources of undue uncertainty in reported reserves are highlighted, and recommendations are given to improve the reliability of reported reserves, especially from unconventional field assets.
Atomic-Force Microscopy: A New Tool for Gas-Shale Characterization
Authors: Javadpour Farzam , Moravvej Farshi Mohammad , Amrein Matthias 
Published: June 2014

Summary
An atomic-force microscope (AFM), a relatively new tool for studying surface characterization, can generate image features down to atomic resolution. Not only can the AFM obtain topographic images of surfaces, but it also can simultaneously identify different materials on a surface at high resolution. Since its invention in the 1980s, AFM has been used in material science and medical research, although it has not received the attention that it probably deserves in reservoir engineering. The emergence of unconventional shale-gas reservoirs, however, has opened new research frontiers for the AFM in the field of reservoir engineering. The unique capabilities of the AFM make it ideal for studying nanopores, organic materials (kerogen), minerals, and diagenetic fractures in shales. It also can be used to measure localized bulk modulus of elasticity on a surface for further implications in geophysical exploration and designing hydraulic fracturing. We introduce different AFM techniques for all these applications, along with example results.
Successful Cementing Through Bottomhole Drilling Assemblies
Authors: Godøy Rune , Grude Sølve , Dyrkorn Cecilie , Illuminati Roberta , Rørvik Ola 
Published: June 2014

Abstract
This paper summarizes 10 years of experiences on pumping cement through bottomhole drilling assemblies - BHAs. Despite a lot of industrial skepticism, a total of 79 cement jobs have been performed through a variety of drilling assemblies, in 3 categories of job types:
Curing critical mud losses to restore well control Plugging back pilot holes Planned plug or squeeze jobs
The job objectives were met for all the cement jobs performed, and high risk well control situations were resolved. The cementing operations have been performed from different types of offshore installations, like fixed platforms, semi-submersible rigs, as well as from TLP's - Tension Leg Platforms.
Most significantly, critical mud losses have been cured by pumping totally 13 cement jobs through rotary steerable drilling assemblies. Losses were cured and well control restored by performing jobs mainly through 8 ½ - and 12 ¼" drilling assemblies. The most severe case handled HPHT conditions and cesium formate drilling fluid.
By taking a controlled risk, the total well risk is significantly reduced. Time and huge costs are saved by performing cement jobs that are instinctively considered as a threat to well control. By planning these cement jobs carefully, the total risk of performing the operation through the bottom hole assembly is reduced.
After gaining experience from some severe, un-planned lost circulation incidents, a best practice was developed and implemented in order to be better prepared, especially for the un-planned events. The same procedures have also been implemented in the planning phase of drilling operations and some cementing operations are planned and executed this way.
Variations in Bounding and Scanning Relative Permeability Curves With Different Carbonate Rock Types
Authors: Dernaika M.R.. R. , Basioni M.A.. A. , Dawoud A.. , Kalam M.Z.. Z. , Skjæveland S.M.. M. 
Published: June 2014

Summary
Relative permeability curves generally exhibit hysteresis between different saturation cycles. This hysteresis is mainly caused by wettability changes and fluid trapping. Different rock types may experience different hysteresis trends because of variations in pore geometry. Relative permeability curves may also be a function of the saturation height in the reservoir.
A detailed laboratory study was performed to investigate relative permeability behavior for a major carbonate hydrocarbon reservoir in the Middle East. Representative core samples covering five reservoir rock types (RRTs) were identified on the basis of whole core and plug X-ray computed tomography (CT), nuclear magnetic resonance (NMR) T2, mercury injection capillary pressure (MICP), porosity, permeability, and thin-section analyses. Primary-drainage (PD) and imbibition water/oil relative permeability (bounding) curves were measured on all the five rock types by the steady-state (SS) technique by use of live fluids at full reservoir conditions with in-situ saturation monitoring (ISSM). Imbibition relative permeability experiments were also conducted on the main RRT samples to assess the relative permeability (scanning) curves in the transition zone (TZ) by varying connate-water saturations.
Hysteresis effects were observed between PD and imbibition cycles, and appeared to be influenced by the sample rock type involved (i.e., wettability and pore geometry). Variations in relative permeability within similar and different rock types were described and understood from local heterogeneities present in each individual sample. This was possible from dual-energy (DE) CT scanning and high-resolution imaging. Different imbibition trends from both oil and water phases were detected from the scanning curves that were explained by different pore-level fluid-flow scenarios. Relative permeability scanning curves to both oil and water phases increased with higher connate-water saturation. Relative permeability to oil was explained on the basis of the occupancy of the oil phase at varying connate-water saturations. The change in the water relative permeability trend was addressed on the basis of the connectivity of water at the varying connate-water saturations. These results and interpretations introduced an improved understanding of the hysteresis phenomena and fluid-flow behavior in the TZ of a Cretaceous carbonate reservoir that can assist in the overall reservoir modeling and well planning.
What the Mating Behavior of Birds Can Teach Us About Corporate Decision Making
Authors: Lehman John 
Published: June 2014

Summary
The combination of computer technology and decision theory has failed to produce the dramatic improvement in the quality of corporate decisions that some predicted. In this paper, I suggest that this failure comes, at least in part, because too little attention has been paid to the environment in which corporate decisions are made. Specifically, this article proposes that corporate decision processes are not constructivist rationality, but more closely resemble the ecological rationality of biological systems shaped by evolution and natural selection. That is, decision processes in corporations evolve over time to satisfy, although not necessarily to optimize, both stated and unstated objectives subject to complex information cost structures and constraints. To illustrate, examples of persistent information asymmetry and economic signaling in nature and in decision processes are shown. Finally, this article suggests that improved understanding of the forces that impact the evolution of corporate decision processes may allow decision theory to come closer to achieving its potential.
Analysis of Transient Linear Flow in Stress-Sensitive Formations
Authors: Qanbari F.. , Clarkson C.R.. R. 
Published: June 2014

Summary
Rate- and pressure-transient analysis of unconventional gas and oil reservoirs is a challenge because of the complex reservoir characteristics that dictate flow. Transient linear flow is usually an important flow regime for these reservoirs and is often associated with linear flow to induced hydraulic fractures. One of the complications in the analysis of this flow regime is stress sensitivity of porosity and permeability. This work provides a new method for analysis of transient linear flow in stress-sensitive tight oil reservoirs.
A correction factor is used to correct the results of the conventional method for analysis of transient linear flow in tight oil reservoirs. A new method is developed for calculating the correction factor by use of an analytical solution to the flow equation. The correction factor is used for production-data analysis of two examples for constant-pressure and constant-rate production. The results indicate that the correction factor becomes more important for higher values of permeability modulus and pressure drawdown. Further, we demonstrate that the correction factor can eliminate the considerable error of the conventional analysis method in estimating initial reservoir permeability or hydraulic fracture half-length.
Pressure Drop versus Flow Rate Profiles for Power-Law and Herschel-Bulkley Fluids
Authors: Omosebi A. O. , Adenuga K. A. 
Published: June 2014

Abstract
The rheological behavior of drilling fluids under static and dynamic drilling conditions is a major concern to both service companies and operators. Most often, a shear stress-shear rate graphical relationship, characteristic of the type of drilling fluid, is used to understand this behavior. Power-law fluids, because of their rheological properties, are majorly used as drilling fluids; the shear stress-shear rate proportionality is non-linear, rather a hyperbolic relationship exists. Herschel-Bulkley fluids, on the other hand, behaves like power-law fluids at low shear rate but deviates from this behavior at high shear rate, demonstrating linear relationship between shear stress and shear rate; a characteristic typical of Bingham plastic fluids.
In order to improve drilling operation with these fluids, understanding pressure drop-flow rate behavior in the annulus is necessary. Using the constitutive equations characterizing these fluids as well as differential equations describing the velocity distribution in the annulus, this paper presents mathematical relationships between mud circulating rate and the associated pressure drop for Power-law and Herschel-Bulkley fluids flowing between parallel plates and through cylindrical pipes. Subsequently pressure drop versus flow rate profiles and annular velocity distributions where generated.
The results show perfect profile-match between the conventional shear stress-shear rate techniques and the pressure drop-flow rate profiles. The outcome of this work can be used to develop pressure drop versus flow rate profiles and annular velocity distribution during drilling. These profiles can then be used to determine pressure drop in the entire drillstring when circulating at any rate. Also, the minimum pump power rating can be estimated from the results of this work. This work is applicable in improving drilling and well completion operations.
Evaluating First Eagle Ford Shale Gas Well—Case History from Northern Mexico
Authors: Araujo Oscar , Lopez-Bonetti Elias , Sierra Jose 
Published: June 2014

Abstract
Northern Mexico has the first major non-associated gas producer basin in the country. However, unconventional reservoirs (mostly very low-permeability shale gas and oil formations) have not been produced so far in this area. These types of reservoirs are located in sedimentary environments where rocks have a high organic-rich content that, when subjected to pressure and temperature conditions, transform this matter into oil and gas. Stimulating a source rock is relatively a new phenomenon in the oil and gas industry. Because these source rock formations have very low permeability, massive hydraulic fracturing stimulation treatments are required to produce at economical rates. Experience and knowledge in drilling and completing wells in this type of reservoir have increased in the last decade. New technologies to evaluate this type of formation and post-production studies have significantly improved, offering better completion methods and techniques.
The Eagle Ford formation in Mexico is located in the northern portion of the country and is considered an extension of the Eagle Ford formation that crosses southern Texas in the United States; during June 2011, production from this US formation was 636 MMscf/D and 97,000 bbl/D.
For the completion of this subject well, which was drilled horizontally, the evaluation techniques, completion plan, and stimulation design were performed using local experience acquired in unconventional reservoirs (tight oil and tight gas) along with experience from the US in shale gas and oil shale formations.
This work shows how this type of formation was identified through several studies, completion was designed and executed, and the fracture treatments were optimized, as well as production matching and forecasting results. This was all performed in the context of an operation that had never been performed in Mexico.
Analysis of Pressure Build-Up and Flow Test Data
Authors: Matthews C.S. 
Published: June 2014

Abstract
Methods of using pressure build-up or flow tests to estimate formation permeability, formation pressure and well damage are reviewed. A number of phenomena which cause actual pressure build-up behavior to differ from the idealized case, such as the effects of boundaries, skins, inhomogeneities, partial penetration and two-phase flow, are discussed. It is concluded that the same method of analysis of build-up curves can be applied with slight modification to oil reservoirs, gas reservoirs and reservoirs producing both oil and gas. The calculations can be carried out on a form sheet, a copy of which is included in the paper. Examples are worked out for four different types of reservoirs.

Introduction
Although the basic theory of pressure build-up behavior in wells was developed many years ago, important contributions since that time have extended the original applicability to a much wider variety of situations. The purpose of the present paper is to summarize the present status of pressure build-up theory and of its applicability.
The approach in this paper will be to start with the simplest type of pressure build-up curve and to show how reservoir rock properties, reservoir fluid properties and wellbore conditions tend to distort the idealized picture. Methods for taking these distortions into account and for determining values of reservoir formation properties from build-up curves will then be considered.
Design and Well Parameters Effects on Run Life of Sucker Rod Pumps (SRP): A Statistical Study for Adiyaman - Turkey
Authors: Ergun Ender 
Published: June 2014

Abstract
After 1859, sucker rod pump was invented commercially by C. E. Drake1, it was used vast majority of wells throughout the world. Thus, it became an oil symbol which comes to mind first for people even who are not engaged in this industry. Although SRPs are installed in about 90% of oil wells in USA, half of wells, 110 are installed by SRP in Adiyaman. Oil and water production is 13,000–13,500 bbl/day and amount of oil is 3,000–3,500 bbl/day.
This study explained that effects of parameters, which are related to reservoir and design, to the mean time between failures (MTBF) of pumps. In this controlled test, MTBF is dependent variable and well parameters are independent variables such as pump diameter, water cut, pump depth, stroke per minute(SPM), salinity and flow rate. These independent variables are examined one by one and completely. All data are taken from 384 well operations in 77 wells and spanned 3.5 years. Index Terms – Sucker Rod Pumps, SRP, Run Life, MTBF, Design Parameters, Well Parameters
Novel Jet-Pump Application Enables Water Flood Project for a Sour Carbonate Reservoir in the Sultanate of Oman
Authors: Al-Hosni F. , Lanier G. H. 
Published: June 2014

Abstract
A sour carbonate reservoir has been identified for water flooding to improve hydrocarbon recovery. The field is situated in the South of Oman and was discovered by PDO in 2005. Production began in 2007 and contains crude oil with 30° API oil gravity and solution GOR of 80 Sm3/m3, as well as, sour fluid contaminants of 5 mol% H2S and 3 mol% CO2. Reservoir water fluid samples confirm salinity is more than 220,000 mg/L chloride ions. While the reservoir is over-pressured at more than 600 bara with a bubble-point pressure of 140 bara, reservoir pressure continues to decline during the initial depletion phase of the field development.
Although water flooding will arrest pressure decline in the reservoir, due to subsurface challenges and uncertainties, artificial-lift is considered a key project requirement during the expected field life. Initially, reservoir water salinity is expected to contribute to an increased risk of salt precipitation and related flow assurance concerns as the water flood approaches the production wells. In addition, expected producing conditions are considered to be extremely corrosive.
This paper will provide a summary of the expected field conditions, water flood project background and key artificial-lift application challenges including the proposed conceptual well completion designs to support the field development. A summary of artificial-lift selection, design and implementation strategy will be explained including objectives, scope and results of the recent jet-pump field trial. Finally, a brief summary of the key conclusions and plans forward will be shared.
Consideration of Voidage-Replacement Ratio in Well-Placement Optimization
Authors: Awotunde Abeeb A. , Sibaweihi Najmudeen 
Published: June 2014

Summary
Determining the optimum location of wells during waterflooding contributes significantly to efficient reservoir management. Often, the voidage-replacement ratio (VRR) and net present value (NPV) are used as indicators of performance of waterflood projects. In addition, VRR is used by regulatory and environmental agencies as a means of monitoring the impact of field-development activities on the environment, whereas NPV is used by investors as a measure of profitability of oil and gas projects. Over the years, well-placement optimization has been performed mainly to increase the NPV. However, regulatory measures call for operators to maintain a VRR of unity (or close to unity) during waterflooding.
A multiobjective approach incorporating NPV and VRR is proposed for solving the well-placement-optimization problem. We present the use of both NPV and VRR as objective functions in the determination of optimal location of wells. The combination of these two in a multiobjective optimization framework proves to be useful in identifying the trade-offs between the quest for high profitability of investment in oil and gas projects and the desire to satisfy regulatory and environmental requirements. We conducted the search for optimum well locations in three phases. In the first phase, only the NPV was used as the objective function. The second phase had the VRR as the sole objective function. In the third phase, the objective function was a weighted sum of the NPV and the VRR. A set of four weights was used in the third phase to describe the relative importance of the NPV and the VRR, and a comparison of how these weights affect the optimized NPV and VRR values is provided.
We applied the method to determine the optimum placement of wells to three sample reservoirs: the first with a distributed permeability field, the second being a channel reservoir with four facies, and the third being a slightly heterogeneous reservoir. Two evolutionary-type algorithms—the covariance matrix adaptation evolutionary strategy (CMA-ES) and differential evolution (DE)—were used to solve the optimization problem. Significantly, the method illustrates the trade-off between maximizing the NPV and optimizing the VRR. It calls the attention of both investors and regulatory agencies to the need to consider the financial aspect (NPV) and the environmental aspect (VRR) of waterflooding during secondary-oil-recovery projects. The multiobjective optimization approach meets the economic needs of investors and the regulatory requirements of government and environmental agencies. This approach gives a realistic NPV estimation for companies operating in jurisdictions with a requirement for meeting a VRR of unity.