bluuebunny/crossref_metadata_2025_split huggingface dataset:
Rock Classification from Conventional Well Logs in Hydrocarbon-Bearing Shale
Authors: Popielski Andrew C. , Heidari Zoya , Torres-Verdín Carlos 
Published: October 2012

Abstract
This paper introduces a rock typing method for application in hydrocarbon-bearing shale (specifically source rock) reservoirs using conventional well logs and core data. Source rock reservoirs are known to be highly heterogeneous and often require new or specialized petrophysical techniques for accurate reservoir evaluation. In the past, petrophysical description of source rock reservoirs with well logs has been focused to quantifying rock composition and organic-matter concentration. These solutions often require many assumptions and ad-hoc correlations where the interpretation becomes a core matching exercise. Scale effects on measurements are typically neglected in core matching. Rock typing in hydrocarbon-bearing shale provides an alternative description by segmenting the reservoir into petrophysically-similar groups with k-means cluster analysis, which can then be used for ranking and detailed analysis of depth zones favorable for production.
A synthetic example illustrates the rock typing method for an idealized sequence of beds penetrated by a vertical well. Results and analysis from the synthetic example show that rock types from inverted log properties correctly identify the most organic-rich sections better than rock types detected from well logs in thin beds. Also, estimated kerogen concentration is shown to be the most reliable property in an under-determined inversion solution.
Field cases in the Barnett and Haynesville shale gas plays show the importance of core data for supplementing well logs and identifying correlations for desirable reservoir properties (kerogen/TOC concentration, fluid saturations, and porosity). Qualitative rock classes are formed and verified using inverted estimates of kerogen concentration as a rock-quality metric. Inverted log properties identify 40% more of a high-kerogen rock type over well-log based rock types in the Barnett formation. A case in the Haynesville formation suggests the possibility of identifying depositional environments as a result of rock attributes that produce distinct groupings from k-means cluster analysis with well logs. Core data and inversion results indicate homogeneity in the Haynesville formation case. However, the distributions of rock types show a 50% occurrence between two rock types over 90 ft vertical-extent of reservoir. Rock types suggest vertical distributions that exhibit similar rock attributes with characteristic properties (porosity, organic concentration and maturity, and gas saturation).
The interpretation method considered in this paper does not directly quantify reservoir parameters and would not serve the purpose of quantifying gas-in-place. Rock typing in hydrocarbon-bearing shale with conventional well logs forms qualitative rock classes which can be used to calculate net-to-gross, validate conventional interpretation methods, perform well-to-well correlations, and establish facies distributions for integrated reservoir modeling in hydrocarbon-bearing shale.
Novel Design and Implementation of Kuwait's First Smart Multilateral Well with Inflow Control Device and Inflow Control Valve for Life-cycle Reservoir Management in High Mobility Reservoir, West Kuwait
Authors: Das Om Prakash , Al-Enezi Khalaf , Aslam Muhammad , El-Gezeeri Taher , Ziyab Khalid , Fipke Steven R. , Ewens Steven 
Published: October 2012

Abstract
Increased hydrocarbon recovery and accelerated production from ultra-high water mobility oil-wet reservoir requires the application of advanced well completion technologies to address premature water breakthrough, reservoir management, production management and extended reservoir contact from a single well location. The Burgan Reservoir of Minagish Field, West Kuwait has active aquifer, very high permeability sands associated with active faults and contain highly viscous reservoir fluid with downhole viscosity of 40cp, enhances water mobility and resulted in premature water breakthrough with increasing water cut trend within few months of production as confirmed from well performance of existing horizontal wells. This has resulted in to non-uniform reservoir depletion, by-passed oil regions and low oil recovery.
The Kuwait's first smart level-4 multilateral well was completed in Burgan reservoir by combining the Level-4 junction along with stacked dual lateral completion having customized viscosity independent Inflow Control Device (ICD), customized two Inflow-Control Valves as well as down hole gauges, wide operating range Electrical submersible Pump (ESP), suitable wellheads, X-MAS tree and Integrated surface panel for real time data monitoring.
The smart multilateral well has assisted in addressing premature water breakthrough, enhanced dry oil production and facilitated uniform depletion, which results in improved hydrocarbon recovery. The paper covers the customized design of smart Level-4 multilateral well by taking in to account the reservoir and its fluid characterization, well architecture, implementation and specially designed invert emulsion drilling fluid for effective wellbore cleanup to achieve formation virginity. The improved reservoir management and production management results are also mentioned in this paper.
Analytical Model to Estimate the Downhole Temperatures for Casing while Drilling Operations
Authors: Kumar Aniket , Samuel Robello 
Published: October 2012

Abstract
The benefits of casing while drilling have become apparent to the industry as complex wells are drilled through depleted reservoirs. Casing while drilling operations help to reduce lost circulation, provide wellbore strengthening, mitigate formation damage, and eliminate non-productive time (NPT). The plastering effect mechanism responsible for pulverizing and smearing the cuttings in the formation to increase the fracture gradient is under extensive research to effectively realize the above benefits. An analytical model used to predict the temperature of the drilling fluid downhole while drilling with a casing will provide an improved understanding of this plastering effect. An estimate of the downhole temperature increases attributable to the persistent contact between the casing and the borehole wall, a characteristic of casing while drilling, will add to the ongoing quantitative analytical studies.
This study proposes an analytical model to analyze the heat generated from the contact between the casing and the borehole wall during a casing while drilling operation and predicts the downhole temperatures of the drilling fluid at any depth of the well. The torque acting on the casing as a result of contact forces was used to model the heat generated, and a steady- state heat transfer solution is presented. The model also incorporates the heat dissipated downhole as a result of frictional pressure losses along the drillpipe, casing, and bottomhole assembly (BHA), as well as energy dissipated through pressure losses across the bit.
The paper presents four practical casing while drilling field cases to suggest potential applications for the proposed model. Downhole temperatures of the drilling fluid were calculated along the well profile, and the increase in mud temperature along the target zones was estimated. The effect of the increase in downhole mud temperatures while drilling with a casing is then analyzed in the context of improving the fracture gradient attributable to the plastering effect. In addition, the effect of drilling parameters on the increase in fracture gradient has also been presented. This simple analytical model can be applied to casing while drilling operations to enhance our understanding of the plastering effect and to use it to our advantage.
Evaluation of Established Perforation Cleanup Models on Dynamic Underbalanced Perforating
Authors: Haggerty Dennis , Craddock G. G. , Quattlebaum Clinton C. 
Published: October 2012

Abstract
The process of perforating in an underbalanced condition has, for many years, been a widely accepted method for ensuring open, clean, and clear perforation tunnels that are conducive to reservoir flow. With the increased popularity of tubing- conveyed perforating (TCP) during the last several decades, this method and the ability to maximize the amount of pressure differential has become even more popular and is often the preferred completion technique. In the last few years, an enhancement to underbalanced perforating, commonly known as dynamic underbalanced perforating, has been examined both through experiments and models. Dynamic underbalanced perforating is a process that creates a negative pressure differential or underbalance, causing fluid to move toward the wellbore even in an initial overbalanced static condition. A dynamic underbalanced condition can be controlled by understanding and carefully managing the temporal pressure transients, using multiple methods within the wellbore during and after gun system detonation. However, fundamental questions remain: What dynamic underbalanced behavior and pressures are required to remove the perforation-crushed zone, and are existing cleanup models sufficient for predicting perforation cleanup given the reservoir condition?
Recently, a series of instrumented perforation experiments using an advanced perforation flow laboratory demonstrated that existing cleanup models do not accurately predict perforation cleanup when perforating in a dynamic underbalanced condition. This work presents initial data and analysis, and suggests a superior method for quantifying perforation cleanup for a given dynamic underbalanced behavior and reservoir condition.
Evaluation of the Carbon Dioxide Response on Pulsed Neutron Logs
Authors: Quinlan Tim , Sibbit Alan , Rose David , Brahmakulam Jacob , Zhou Tong , Fitzgerald John , Kimminau Steve 
Published: October 2012

Abstract
Carbon Dioxide (CO2) sequestration and enhanced recovery projects require the evaluation of rocks containing mixtures of CO2, water, and gaseous or liquid hydrocarbons. Pulsed neutron logs of various designs and measurement types have been used since the 1960s to evaluate formations containing gaseous hydrocarbons, but they were not originally designed or characterized specifically for quantitative CO2 evaluation. Computer modeling, test pit data, and field examples are presented in this work to highlight the issues of CO2 evaluation and to compare these with gaseous hydrocarbons.
Pulsed neutron tools emit 14 MeV neutrons from an accelerator source, but a wide variety of timing sequences, detector types, source-detector spacings, and signal processing techniques are employed by the industry to extract formation description parameters from the recorded counts. For the non-specialist petroleum engineer this variety can confuse and distract from effective use of the measurements. We organize all categories of pulsed neutron logs into simple types based upon the measurement physics to provide an effective guide to field use of these logs.
Examples of commercial and experimental tools in clastic and carbonate environments are presented. The examples show how CO2 can be quantified and demonstrate critical design requirements for successful pulsed neutron logging campaigns. We outline the lessons learned and make recommendations for the design of logging programs and interpretation of the acquired data in stand-alone or in time-lapse modes.
Modeling of Wettability Alteration Due to Asphaltene Deposition in Oil Reservoirs
Authors: Darabi Hamed , Sepehrnoori Kamy , Kalaei Mohamad Hosein 
Published: October 2012

Abstract
Wettability is a key property, which controls multiphase fluid flow in oil recovery processes. It is well known that the asphaltene deposition on rock surface changes the wettability of the rock. Although many experiments in the literature have been conducted to understand the physics underlying wettability alteration in crude oil/brine/rock (COBR) system because of asphaltene deposition; a sophisticated mathematical model describing this phenomenon is absent.
In this paper, based on available experimental data in the literature and known physical mechanisms of asphaltene deposition on the rock in the COBR system, a model for wettability alteration due to asphaltene instability in crude oil is presented. Contact angle is introduced as a function of asphaltene stability index (ASI), which is determined thermodynamically based on the difference between the fugacity of asphaltene and the heaviest component in the oil. The shape of this function depends on pH, salinity and cation valency of brine, and asphaltene content of crude oil. We implemented our proposed model along with asphaltene precipitation, flocculation, and deposition models into an in-house compositional simulator, UTCOMP, developed at The University of Texas at Austin. Permeability and porosity reduction due to asphaltene deposition are also considered. Furthermore, relative permeabilities and capillary pressure are modified because of contact angle alteration during simulation.
Although the amount of asphaltene deposition in the reservoir may not be comparable to the wellbore, a significant change in wettability occurs after the deposition of first layer of asphaltene on the rock surface. The result of our simulation shows that wettability alteration affects oil recovery, specifically when the brine produces unstable water film on the rock surface. In this case, rock wettability can change from 30° (water-wet) to 150° (oil-wet) and yield change in recovery depending on absolute permeability reduction magnitude and change in trapped oil saturation as well as end-point relative permeability.
New Pressure-Actuated Valve Allows for Interventionless Access to Formation in Cemented Applications
Authors: Johnson C. Christopher , Kellner Justin , Mailand Jason 
Published: October 2012

Abstract
Unconventional reservoirs require innovative completion techniques and technology to become more economical. Formations vary drastically in lithology, lateral lengths, completion methods, and financial drivers. One of the most common techniques is the ‘plug-n-perf’ method. In the Eagle Ford, long-string completions are the norm, with the production casing cemented in place along the horizontal section and up the vertical section, providing isolation between frac stages and from other formations above and below the zone of interest.
The Eagle Ford shale is a formation that produces gas, liquids, and oil, depending on the area in South Texas being drilled. Operators are looking for ways to reduce cost and gain efficiencies when completing wells in unconventional reservoirs. One way of reducing cost is eliminating coiled-tubing-deployed perforations for establishing reservoir communication on the first stage of multistage frac operations.
Technology has been developed which provides operators the option of placing a pressure-actuated valve above the shoe track, allowing for standard cementing practices. The new valve provides operators the ability to pressure test the casing and, through the use of applied pressure from the surface, activate into the open position. Once opened, information about the reservoir can be gathered that will influence the frac design before assembling the required pumping equipment.
This paper presents multiple case histories showing different applications of the cemented pressure-actuated valve. The development history, reliability, and inherent accuracy are presented. This interventionless access technique has been proven effective in the Eagle Ford and Haynesville formations and is applicable in other unconventional reservoirs requiring multistage hydraulic fracturing.
Portfolio Optimization in High and Low Risk Environments
Authors: Rodriguez Luis , Moreland Brian , Kirk Graham 
Published: October 2012

Abstract
Upstream oil and gas is a very capital intensive business. Shareholders look for profitability and growth against a backdrop of declining production and decreasing new play sizes. Optimal project selection is necessary to maximize the potential of any portfolio or business plan. The main goal of a Business Plan is to select a portfolio of projects (drilling, exploration, etc.) that maximizes value (and minimizes risk) and satisfies all constrains faced by management (drilling rig availability, facilities capacity, capital availability, human resource availability, etc.)
These problems can be expressed in the form of a set of linear or non/linear equations such that global optimum values can be determined using Linear Programming or Genetic Algorithms. In this paper we will show how these techniques can be used to solve optimization problems utilizing a combination of both techniques and the use of software designed for that purpose.
In our case study, we were able to define and implement a plan that increased expected production, reduced capital requirements by 20%, kept the activity within the capacity of the drilling rigs and facilities available and clearly prioritized the proven undevelop reserves within a maximum of 5 years for planned development. The total time invested on designing the plan was less than 5 days and the execution became clear to all the parts involved via a tool to share the information. The plan as designed was executed in 2011 flawlessly.
A Decade of Deepwater Gulf of Mexico Stimulation Experience
Authors: Morgenthaler Lee N. , Fry Leigh A. 
Published: October 2012

Abstract
The deepwater Gulf of Mexico is a technically and economically challenging production environment. High rate and ultimate recoveries per well are required to offset high development costs. Stimulation is employed to maintain wells at peak production rates and accelerate reserve recovery. In the complex layered reservoirs of the deepwater Gulf of Mexico stimulation is also necessary to ensure volume recovery. The primary objective of stimulation is to restore impaired well /reservoir connectivity. In complex reservoirs this may be reflected in either a reduction of skin or improvement in apparent permeability height. In poorly consolidated sandstone reservoirs production may become impaired during completion operations by suspended solids, polymer residue, or incompatible fluid systems. During production fines migration, scale deposition, and organic deposits in the near wellbore and sand control system can lead to declining inflow performance. Successful identification of the cause and location of impairment is required for success. The increasing population of subsea wells creates new challenges for intervention. Correct operation of the well post stimulation is also necessary to achieve the desired rate increases without compromising production system performance. The nature of impairment, treatment options, and post treatment production issues often change over the life of the well. Looking back over a decade of experience in this challenging environment yields useful insights as we move into new deepwater provinces.
Evaluating an Engineered Completion Design in the Marcellus Shale Using Mircoseismic Monitoring
Authors: Wutherich Kevin , Walker Kirby , Aso Iroh , Ajayi Babatunde , Cannon Tom 
Published: October 2012

Abstract
It has long been accepted that one of the most cost-effective strategies for completing a horizontal shale gas well is to pump several fracture stimulation treatments along the lateral with each treatment contacting several perforation clusters spread out over a few hundred feet. Typically, these clusters are placed geometrically from toe to heel with the same distance between clusters and no other consideration as to the location of these perforations.
While this process simplifies the design of the completion, there are indications that this can be ineffective in contacting the maximum amount of reservoir. The fracture treatment will tend to follow the path of least resistance; intervals where stresses are the lowest will be preferentially stimulated over intervals that have higher stress concentrations. This effect was very clearly seen in a recent stimulation campaign performed in the Marcellus shale. During the fracturing treatments on several laterals, large gaps in microseismic events were observed where some perforation clusters appeared to take little to no fluid. Outlined in this paper is one particular example where even with use of a very aggressive limited-entry perforating technique, which uses perforation friction pressure to help distribute flow equally to each perforation, microseismic monitoring still showed 35% of the clusters receiving no fluid.
To improve stimulation coverage, two completions were designed using data acquired from horizontal well logs. Interpretations of lithology and stress along the wellbore allowed perforation selection in these wells using a newly developed software platform in such a way that the induced fractures were afforded the best chance of distributing equally along the lateral. Microseismic monitoring obtained during the stimulation of these wells clearly indicated significantly better fracture coverage. Additionally, stimulation treating pressures were reduced by targeting lower stressed sections, resulting in less difficulty placing proppant.
Laboratory and Field Evaluation of Proppants and Surfactants used in Fracturing of Hydrocarbon Rich Gas Reservoirs
Authors: Penny Glenn , Zelenev Andrei , Long Wei , Lett Nathan , Crafton James 
Published: October 2012

Abstract
The productivity and economics of horizontal wells are governed by the ability of the transverse fractures to communicate efficiently with the wellbore, which is strongly controlled by the conductivity of the proppant bed and the effectiveness of the fluid additives. These impact the relative permeability, the capillary pressure and the effective conductivity in the proppant bed. If the wellbore is high in the fracture, gravity segregation will cause liquid removal from the lower portion of the fracture to be very difficult. In low conductivity proppant beds, capillary pressure will tend to retain high water saturations, thus lower the effective conductivity even for the portions of the fracture above the wellbore.
Laboratory and field studies are presented comparing various sizes and types of proppants and the influence of surfactants used in oil bearing formations including commonly used demulsifiers and a multi-phase complex nano fluid system. Ammot cell and centrifuge tests were used to evaluate imbibition of oil and water. Columns packed with proppant and formation cuttings are used to compare the effectiveness of various additives in allowing the displacement of water and establishing oil flow. Results are correlated with interfacial tension, contact angle, capillary pressures and surface energies of actual formation materials, oils and treating fluids from the Niobrara, Bakken, Granite Wash and Eagleford formations. Simulations are presented that show the impact of capillary pressure and oil viscosity on the displacement of fluids.
Field results from various fields including the Niobrara, Bakken, and Marcellus formations are presented. The normalized field data shows that wells with higher conductivity proppants and properly selected surfactant packages result in longer effective frac lengths and greater normalized oil and gas production. Correlations are made between the observed relative perms in the lab vs. the observed field results.