bluuebunny/crossref_metadata_2025_split huggingface dataset:
Practical Considerations for Forecasting Production Data in Unconventional Reservoirs — Variable Pressure Drop Case
Authors: Collins Patrick , Ilk Dilhan , Blasingame Thomas Alwin 
Published: October 2014

Abstract
The premise of this work is the development, validation, and application of a methodology to forecast production data in unconventional reservoirs where variable rate and pressure drop producing conditions are typically observed. In unvonentional reservoirs, it is not common practice to maintain or even arrive quickly upon a constant flowing bottomhole pressure which is the primary assumption for the application of traditional time-rate decline curve analysis. As a result the application of traditional time-rate relations to these cases yields misleading results (i.e., EUR values) at best.
Our methodology involves the application of the rigorous convolution/superposition theory with the pressure drop normalized "empirical" rate decline relations as the "well/reservoir" model and the "measured/calculated" pressure drop data. Diagnostic plots of the loss ratio and the loss ratio derivative, or the so called "qDb" plots, are utilized to minimize the non-uniqueness inherent in the history matching process by providing guidance in the selection of rate decline model parameters. Following the selection of model parameters, the normalized rate decline relations are superposed with pressure (or pseudopressure) drop data to achieve a history match and, correspondingly, a production forecast.
Validation and application of the methodology is demonstrated using a variety of synthtic data generated to closely represent common operational practices in tight/shale oil and gas plays. A special emphasis is placed on handling non-linearities and performing sensitivities to account for future drawdown management. We show that the methodology effectively removes pressure variations from the rate history for each of the synthetic examples presented. We present our results using a variety of diagnostic and forecasting plots and both the magnitude of the EUR and the shape of the production profile for all cases.
Introduction
Decline curve analysis (DCA), or the extrapolation of only "time-rate" production data into the future, is one of the most commonly used techniques in the petroleum industry to estimate ultimate recovery (EUR) for producing wells. Essentially decline curve analysis refers to the calibration of a time-rate model, or decline curve, to a single well (or multiple wells) and extrapolating production to an abandonment limit to yield an estimate of ultimate recovery.
he simplicity of the method along with the fact that production from conventional reservoirs honors most of the underlying assumptions have led to Arps' hyperbolic and exponential decline curve relations becoming the industry standard for production forecasts (Arps 1945). Johnson and Bollens (1927) laid the foundation for the exponential and hyperbolic relations when they introduced the loss ratio and the derivative of the loss ratio which are given below.
Environmental Risk and Well Integrity of Plugged and Abandoned Wells
Authors: King George E. , Valencia Randy L. 
Published: October 2014

Abstract
This paper is the third in a series of environmental risk assessments covering hydraulic fracturing (SPE 152596) and well construction (SPE 166142). Risk assessment and well failure from SPE literature and governmental agencies have been used to construct a detailed but non-company associated study of plug and abandonment (P&A) objectives, problems, best practices, application details and methods. The objective is to identify technology improvements as well as potential or proven problem areas. Technology gaps will be related where they are identified by either problem reports or failures.
Case histories have been captured that illustrate a variety of abandonment reasons and approaches in plug setting, isolation and testing/monitoring methods. The study well groupings are divided by age and era or vintage of abandonment to examine the worth of technologies in force at the time of abandonment. Well age, well type and general geographic influences are presented with notation of specific problems and conditions that challenged effective isolation.
Special attention will be paid to cases of failed isolation as cited by the governmental inspection and/or governing body as well as repair methods that restore integrity. Attention will also be given to problems encountered in older wells. Lessons gleaned from this study will be of value to well construction and operational maintenance with consideration paid to well type, geological hazards, production history and durability of the isolation seal.
Modeling the Effects of Anomalous Electromagnetic Diffusion on Induction Logs: The Next Step in Mapping Natural Fracture Corridors
Authors: Elliott Marcus , Everett Mark E. , Heidari Zoya 
Published: October 2014

Abstract
Fracture detection and characterization are challenging aspects of completion plans for unconventional tight carbonate and shale reservoirs. Current industry methods, such as high resolution resistivity imaging, mitigate uncertainties in fracture characterization, but are not cost effective or always available. Conventional well logs (e.g., induction logs) can be better solutions for the industry for reliable fracture characterization. However, these measurements do not provide significant sensitivity to fracture location and geometry. An improved evaluation of thickness and near-wellbore geometry of induced fractures using conventional well logging tools could significantly enhance operational decisions and increase production during field development.
We propose the use of surface gas readings and downhole measurements in combination with numerical simulations of electromagnetic induction log responses to define and high-grade natural fracture corridors. We performed numerical simulations to model the effects of hydraulic fractures on induction log response, within the fractured zones. These simulations consisted of placing resistive fractures, with variable parameters, inside a layered formation, and modeling the apparent resistivity using an induction logging simulator. The fractured zones were represented using a geologic roughening parameter, β, while the simulator is based on the finite element method. The simulator, Seatem, solves the diffusive Maxwell equations, and plots the resulting apparent resistivity distributions within an unstructured tetrahedral mesh. This provides us with a good understanding of how the targeted zone interacts with different stimulation factors.
We successfully performed numerical simulations along a multi-zoned reservoir interval for three synthetic cases: a sandstone formation, a carbonate formation, and an organic shale formation. We quantified the effects of hydraulic fracturing on induction logs and optimized placement of fracture treatments on synthetic cases. The results of this paper indicate fractured zones with beta values larger than 0.3, viable for fracture corridor depletion and geologic targeting, can be identified from induction log responses.
60 Years of Multi-Fractured Vertical, Deviated and Horizontal Wells: What Have We Learned?
Authors: King George E. 
Published: October 2014

Abstract
Multiple fracture placements in single wells have a sixty year history with first applications soon after hydraulic fracturing was patented. Fracturing technology has been applied to offshore deviated wells, sand control wells, tight gas, coal, chalks, shales and conglomerates in turn as "conventional" reservoir limits were reached and each "new unconventional" reservoir was encountered. As fracturing technology was adapted to make an "unconventional" reservoir into a conventional reservoir, the adaptations and evolutions needed became part of the technology tool box waiting for the next challenge. Each innovation improved and stretched the reach of completions and production engineering as new findings were incorporated to monitor, model, optimize and extend the ranges of fracturing use for high and low temperatures, high stress formations and a variety of other challenges.
This review looks at the development of multi-fractured wells from its first application in vertical wells where one well could now do the task of three wells, to the first modern application of highly multi-fractured horizontal wells used in chalks, shales and tight oil and gas reservoirs. The technical focus is on the learning procession covering details of casing wear, cyclic pressure application, isolation mechanisms, perforation placement, well spacing and fracture spacing.
The technical literature and field learnings have both been searched for applicable information with a surprising variety of engineering application details brought forth that are useful in optimizing a single well or a whole development.
Multivariate Control for Managed Pressure Drilling Systems Using High Speed Telemetry
Authors: Shishavan Reza Asgharzadeh , Hubbell Casey , Perez Hector D. , Hedengren John D. , Pixton David S. , Pink Anthony P. 
Published: October 2014

Abstract
With the recent advance in high speed data communication offered by wired drill pipe (WDP) telemetry, it is now possible to design automated control systems that directly utilize downhole data (e.g. pressure) to optimize drilling procedures. This research couples drilling hydraulics, rate of penetration (ROP), and rotational speed (RPM) control into a single controller for managed pressure drilling systems. This novel multivariate controller improves drilling performance during normal drilling operations and enhances safety during abnormal drilling conditions such as unwanted gas influx situations.
New advances in drilling automation have made the closed loop control of downhole weight on bit (WOB) and drill string rotational speed (RPM) possible. This study uses two feedback controllers that control the downhole WOB and RPM using surface data. A multivariate nonlinear model predictive controller (NMPC) uses downhole and surface measurements to simultaneously regulate the bottom hole assembly (BHA) pressure and maximize the ROP. For this purpose, NMPC provides the necessary set points for the WOB and RPM feedback controllers as well as manipulates the choke valve opening and pump flow rates. Controller performance is enhanced via a nonlinear estimator that works continuously online with the NMPC and provides the necessary estimated parameter values (i.e. annulus density, friction factor, and gas influx) for precise and efficient drilling control.
The designed NMPC controller has a multi-priority approach which is described in the following three scenarios: (1) during unexpected gas influx, the NMPC gives priority to BHA pressure control and attenuates the influx effectively via a novel kick attenuation method that switches the control objective from BHA pressure to choke valve pressure; (2) during connection procedures when adding a new stand, ROP is stopped and the NMPC focuses on maintaining the BHA pressure constant; (3) during normal drilling operation, which involves changes in the rock formation and differential pressures, NMPC gives priority to ROP maximization while maintaining RPM, WOB, and BHA pressure within specified bounds.
Preliminary results suggest that this multivariate controller for ROP and BHA pressure control will decrease drilling costs, reduce operator workload, and minimize risk significantly. Specific improvements in drilling performance include higher ROP, effective kick attenuation, and more uniform cuttings. The use of a multivariate NMPC allows for better ROP optimization and BHA pressure control than would be possible with the use of two independent controllers. These benefits are demonstrated across the three scenarios mentioned above. This technology has potential to deliver significant performance improvements during managed pressure drilling and further the development of auto driller systems.
Petroleum Senior Students Specialize in Operations or Reservoir Engineering
Authors: Heinze Lloyd R. , Watson Marshall C. , Herd Bob L. 
Published: October 2014

Abstract
The Bob L. Herd Department of Petroleum Engineering at Texas Tech University has significantly revised the curriculum for the senior year. In response to industry, Texas Tech's petroleum industry advisory board, senior exit interviews, and surveys from recent graduates; the faculty have altered the senior course offering. The major concerns expressed centered on providing students with sufficient course work in both Reservoir / Formation Evaluation (RFE) and Drilling / Production Operations (DPO). Adding four additional courses would exceed the reasonable limits of a four year undergraduate BS degree. A 148 hour program would approach conventional MS degrees. The department decided to leverage existing low level master courses to allow seniors to select a RFE or DPO specialty. The goal is more depth and a little less breadth.
During their senior year, students elect to take four RFE or four DPO courses along with the other required senior petroleum courses. This has allowed an interesting dynamic in the two senior semester design sequence. Teams are formed with course background of both RFE and DPO courses. This has also changed the material covered during semesters four, five, and six (sophomore and junior semesters). Students will only have a minimum of coverage in either RFE or DPO courses in semester four-six. During these three semesters, the department significantly ramped up the petroleum material covered. Departments of Geology, Energy Commerce, and Industrial Engineering have provided petroleum related course improvements to further enhance the student outcomes.
The department has completed its first year of the new curriculum, and plans to share the results at the next SPE Annual meeting. These changes have been tracked using ABET methods to assess and improve the program.
The vision was to enhance undergraduate student understanding of the theory and equations taught by building concepts of procedure and construction. Designing procedures for oil field operations and evaluation is key to developing critical thinking. Concepts of largeness of scale of the industry, timing and logistics, and the ability to "critically think" about the reservoirs and fluids; all under conditions that are not observeable in their downhole "native" state are extremely difficult to convey through equations and computer program "black boxes." The faculty and industry advisory board noted a gradual movement of recent graduates to rely on "plug and chug" putting values in equations and computer black boxes prior to determining whether the numbers input are correct or accurate. Students were relying too much on the computer answer without ensuring the values represented a reasonable result. They often didn't question the magnitude or the significant figures (accuracy) of their answers. In addition to understanding magnitude and accuracy, students are taught the uncertainity that petroleum engineers must deal with is a critical distinction of the profession.
Integrated Management Strategy of Flow Assurance for Digital Field
Authors: Zhang He , Li Jun , Khor Siew Hiang 
Published: October 2014

Abstract
Nowadays the oil and gas industry devotes great attention and efforts to unconventional hydrocarbon resources. Production operations on these resources are often challenging due to possible complex risks, and flow reliability can become a key concern upon high intervention costs. Understanding and managing the related risks require detailed multidisciplinary engineering analysis involving accurate fluid characterization and advanced multiphase flow simulations. This practice of ensuring successful and economical flow of hydrocarbons is called Flow Assurance (FA); which alsohas become a substantial consideration in reservoir management.
This paper firstly presents an innovative rating system covering all types of FA problems by Design of Experiments (DoE) and Fuzzy Logic methods respectively. With the emerging digital field technologies, this work can subsequently propose an integrated management workflow on addressing various FA issues. Supported by a case study, this paper demonstrates the importance of this decision-making process in light of the proposed workflow. A remedy for one identified FA problem may result negative side effects for a production system over years, and subsequently decrease the reserves and the project profitability.
A Practical Petrophysical Approach for Brittleness Prediction from Porosity and Sonic Logging in Shale Reservoirs
Authors: Jin Xiaochun , Shah Subhash , Truax Jerome , Roegiers Jean-Claude 
Published: October 2014

Abstract
Brittleness has been used as one of the important descriptors for the characterization of unconventional shale reservoirs. The degree of brittleness in shale reservoirs is determined upon the basis of its mineralogical composition, which can be obtained from mineralogical logging tools (such as ECS™, FLeX™, GEM™, Litho Scanner™), or XRD tests in the laboratory. Generally, measurements of mineralogical brittleness are obtained from physical sources and lead to relatively reliable interpretation results. However, mineralogical logging is expensive and not commonly available in the shale play. Alternatively, brittleness can also be calculated from dynamic Young's modulus and Poisson's ratio, but the absence of shear slowness in some wells restricts its wide application. Internal friction angle based brittleness can give similar interpretation results as the preceding two methods, but its accuracy depends highly on the quality of correlations. It is observed that the curves of the three different brittlenesses demonstrate similar shapes. Therefore, we have attempted to build correlations between mineralogical brittleness and porosity or sonic compressional slowness for typical shale plays (Woodford, Barnett, and Eagle Ford shale), and have proven their validity with the data obtained from wells not included in the development of correlations. Applications of these findings include: (1) enabling the possibility of evaluating brittleness in plays lacking mineralogical and shear sonic loggings, thus reducing the quantity of laboratory testing, (2) inspiring operators to develop in-house correlations of brittleness for shale gas plays, and (3) investigating similar correlations in emerging unconventional oil plays, such as Granite Wash.
Proactive Novel Approach and Design Strategies to Zonal Isolation in a Highly Challenging Deep Water Environment
Authors: Grant Lisa , Japar Nor Janiah , Reagins Deandre , Hale Arthur , Mercado Steven , van den Haak Arno L.M. , Lloyd Russell , Pereira Andre Guilherme 
Published: October 2014

Abstract
In September 2010 a decision was made to expand the current Mars field development with a second 24 slot TLP structure in a water depth of 3000 ft. This new development includes higher pressured deeper pays below the existing brown field Mars pays. The new structure will install wells with multiple casing strings across stacked sand packages that are both depleted and virgin pressured ranging from 10,500 ft to 23,000 ft TVD in depth. This in combination with other challenges such as extremely tight annuli clearances, depletion zones greater than 5000 psi, multiple stacked sands at varying degrees of depletion, and risk of borehole stability failure/ballooning presents a unique set of zonal isolation challenges that requires proactive novel approaches and design strategies. Zonal isolation is a regulatory requirement and a key component of project success in order to secure maximum field recovery and future wellbore utilization within the estimated field life.
Zonal isolation methodology and design does not have a single focus but explores all parameters that affect placement and isolation while not losing focus on striving operational simplicity. This paper discusses the engineering approach to zonal isolation requirements in a highly challenging environment utilizing a step wise methodology with increasing complexity and also elaborates on how this approach led to the identification and ultimately the development of new technologies.
Design methodologies will be discussed as well as resulting technologies identified as a "must haves" for development to ensure maximum probability of zonal isolation success. Technologies discussed will include reverse cementing tools, 50 (+) year seals for stage collars, and connection requirements. Statement of Requirements (SORs), basic tool descriptions, and preliminary results of these developments will also be included. Discussions on why certain placement techniques or approaches were not integrated into the zonal isolation project plan will also be discussed.
Subsea Well Intervention: Recent Developments and Recommendations to Increase Overall Project Returns
Authors: Nelson M. E. , McLeroy P. G. 
Published: October 2014

Abstract
As the subsea industry ages, the number of premature subsea well shut downs are increasing due to insufficient well intervention programs. In the past, subsea well interventions have not been widely used because of a lack of economic feasibility; however, with appropriate project planning, the recent economic climate, and advances in well intervention technology, a greater overall project return can be realized by implementing a proactive well intervention program. While intervention on surface wells is a familiar topic, the benefits and negative consequences of more recent subsea intervention developments, such as riser-less light well intervention, riser-less mud return, and well flow back and testing, are evaluated. These different well intervention methods carry varying amounts of risk with them, with the potential to greatly enhance or diminish well performance and thus affect recoverable hydrocarbons. The risks involved with the different well intervention methods are evaluated and recommendations are made as to which methods are utilized depending on desired return rates and risk aversion levels. Recommendations are made for implementing a successful well intervention program, such as production monitoring, scenario planning, application of a dedicated multi-disciplinary team, cross-organizational collaboration, and logistical improvements. With an effective well intervention program, reservoirs can be further exploited, potentially increasing project return and supplying hydrocarbons to a demanding global market.
Predicting Production Behavior of the Marcellus Shale
Authors: Mashayekhi A. , Belyadi F. , Aminian K. , Ameri S. 
Published: October 2014

Abstract
The long-term production behavior of horizontal wells producing from Marcellus shale due to limited production history has not been well established. As a result a simple method for predicting the long-term production and reserves would be of interest. Several production decline curve analysis models have been proposed specifically for application to unconventional gas reservoirs. However, reliable production predictions cannot be obtained when they are applied to limited production history such as those available from Marcellus shale wells. In this study, the production and completion data from a number of horizontal wells completed in Marcellus shale were collected and used to build a generic model. The model was then in conjunction with a commercial dual porosity numerical model which included the adsorbed gas to simulate long-term production profiles for Marcellus shale horizontal wells with multiple hydraulic fracture stages. The simulated production profiles were then utilized to develop correlations for adjusting the conventional (Arps) decline curve constants obtained to from the limited production history to accurately predict the long-term production performance. The impacts of key formation and fracture properties on the decline curve constants were also investigated. Finally, the correlations were utilized to accurately predict the long-term production rates from a Marcellus shale horizontal well in West Virginia based on the early production history.