bluuebunny/crossref_metadata_2025 huggingface dataset:
Fault Reactivation as Mechanism of Early Water Production in Unconsolidated Sandstones Reservoirs
Authors: De Luca S. M. , Oliveira R. F.
Published: October 2014

There are several case studies showing that water injection apparently induces fault reactivation in oil and gas fields. However, there are not many publications in literature relating water production increasing with fault reactivation caused by depletion. The unexpected water production by fault reactivation related to depletion, promotes a huge impact on an oil field production, reducing the reservoir drainage efficiency and causing premature aging of operating plants, in some cases generating production bottlenecks due to produced water treatment limitations.

This paper presents parameters that influence fault reactivation mechanism and their importance in early water production.

In order to evaluate the phenomenon, a failure stability parameter that can be monitored during reservoir production time life is proposed and its behavior can be analyzed by comparison with produced water rate. The methodology is based on Mohr-Coulomb failure criterion using a simplified approach.

Basically, the method considers the change in the state of effective stresses, vertical and horizontal, during production and its ratio (σh/σv) called K0.The relationship of effective stress necessary for the Mohr circle touches the envelope of rupture for a given frictional angle, called K1, is also considered.

Thus, it is possible to observe the stress state changing as field production occurs using flow simulation. Fault reactivation analysis is obtained from the difference K0 minus K1, being K0 less or equal to K1, the condition at which depletion can induce faults in the reservoir. The method has been successfully applied on an unconsolidated sandstone reservoir from Campos Basin, explaining the evolution of anomalies in BSW (basic sediment and water) values that could not be predicted ignoring the theory of fault reactivation by depletion.

Recognizing that fault reactivations contribute to the unexpected water production is an important changing of paradigm in oil industry. The determination of the parameter of reactivation by depletion constitutes an important mark to indicate the right moment for beginning waterflooding. Many mature fields that present high Water Cut values, previously thought to have occurred due to rising of water-oil contact, may be revisited and restudied using the theory of fault reactivation by depletion. The approach can help to identify undrained-overlooked areas where infill drilling projects could be implemented, extending oil production and increasing oil recovery factors.
Probabilistic History Matching of Dual-Porosity and Dual-Permeability Korolev Model Using Three Discrete Fracture Models
Authors: Abdrakhmanova Aizada , Iskakov Elrad , King Gregory R. , Chaudhri Moon Mansoor , Liu Ning , Bateman Phil
Published: October 2014

Tengizchevroil (TCO) operates two giant carbonate oil fields, Tengiz and Korolev, located on the northeast shore of the Caspian Sea in Kazakhstan. Both fields are Middle Devonian to Upper Carboniferous isolated carbonate platforms. Since 1991, the fields have produced around 2B barrels of oil. As more geologic and dynamic data becomes available, an updated history match of the existing dynamic field models is required to provide more accurate simulation results for estimating reserves, optimizing production and assessing future field development opportunities.

In this paper, we present a case study on the use of brown-field design of experiments (DoE) on dual-porosity and dual-permeability Korolev field simulation model. Korolev is a highly fractured reservoir, and the physics of fluid movement is mainly controlled by the fracture network. In order to capture the uncertainty in the extent of fracture region at Korolev, discrete low, mid and high fracture models were created. The history matching process was split into three separate DoE studies, one for each of the fracture models, to obtain good quality proxies. After history matching the three fracture models separately, a combined proxy was created, and the final probabilistic P10, P50, P90 models were selected from the suite of all low, mid and high fracture extent models.

The history matching workflow consisted of selecting uncertainty parameters and ranges which honor geological data, identifying parameters having high impact on the history match quality, conducting brown-field DoE of historical and prediction periods, developing proxies for EUR objective functions and history match mis-match functions, and model selection. The majority of history matching effort was spent on the static well pressure match, followed by minimizing the modular dynamic test (MDT) pressures, production logging tool (PLT) profiles and water cut mis-match functions. Approaches in key areas which helped to improve the quality of Korolev history matched models will be discussed in detail.

The history matching workflow with low, mid and high fracture models described in this paper is believed to be superior to approaches that use a single fracture realization with fracture porosity, fracture permeability and sigma (fracture-matrix interaction term) history match modifications within the simulator. This is because the use of three fracture realizations allows for adjustment of intrinsic fracture properties (fracture density, aperture size, fracture extent, etc.). In addition, the use of three separate DoE studies allows for more accurate proxy model development.
A Workflow for Intelligent Data-Driven Analytics Software Development in Oil and Gas Industry
Authors: Dursun Serkan , Duman Kaan , Tuna Tayfun , Abbas Mamta , Ding James
Published: October 2014

A vast amount of oil and gas data has been collected over many years, which can be classified into different groups, including numerical, categorical, historical, real-time, structured, and unstructured. Therefore, analysis and visualization cannot be efficiently accomplished using traditional software platforms. Companies in the oil and gas industry need new technologies and processes to capture and transform data into strategic business intelligence to enhance exploration and production, improve refining and manufacturing efficiency, and optimize global operations while ensuring safety and environmental protection. With the advent of machine learning, data mining, optimization, and cloud computing, it is now possible to manage the large amount of data as never before.

Data-driven analytics, in this concept, offers new capabilities to the engineer in exploration and production to learn from data. Analyzing patterns in historical data and identifying the events in real-time data are two methods used for improving operations of activities and assets. The application of data-driven analytics in the oil and gas industry, therefore, potentially provides opportunities for greater insight and efficiency gains. The goal for data-driven analytics software is to provide the strategy required to optimize business outcomes and decision making while helping to minimize risk. The interaction between the users and the information through software tools results in a decision process that helps determine success of a project. The development of a data-driven software platform involves combining a variety of advanced machine learning and data-mining techniques, as well as data management strategies, to provide fit-for-purpose descriptive, predictive, and prescriptive models. Therefore, to be successful, the development team should have a deep understanding of both the underlying data science and the business model as well as software engineering principles.

This paper presents a workflow for an intelligent data-driven software platform development. The proposed workflow is composed of data management, data analytics and visualization, and predictive modeling. It covers best practices on database design, object-oriented design patterns and principles, predictive model building and deployment, user-interface development, and test-driven software development in an agile software development structure.
Economic Co-optimization of Oil Recovery and CO2 Sequestration
Authors: van't Veld Klaas , Wang Xiao , Alvarado Vladimir
Published: October 2014

Drawing on techniques from both petroleum engineering and economics, we analyze how oil fields that use CO2 injection to enhance oil recovery (CO2-EOR projects) are likely to respond to incentives that promote CO2 sequestration. Most engineering studies that have examined how oil-field operators should "co-optimize" oil recovery and CO2 sequestration use sophisticated reservoir models, but ad hoc economics. Conversely, a study by Leach et al. (2011), which to date is the only rigorous economic study of co-optimization, uses sophisticated economics, but an ad hoc reservoir model. Our study bridges the gap between these studies, by applying Leach et al.'s analysis to dynamic reservoir-simulation models of two different oil fields. We find that, even though Leach et al.'s assumptions about how a reservoir responds to CO2 injection are quite far off the mark quantitatively, their main findings hold up remarkably well qualitatively.
Experimental Study and Modeling of the Effect of Pore Size Distribution on Hydrocarbon Phase Behavior in Nanopores
Authors: Wang Lei , Neeves Keith B. , Yin Xiaolong , Ozkan Erdal
Published: October 2014

Pore sizes of many shale and tight oil and gas reservoirs are in the range of nanometers. In these pores, the phase behavior of hydrocarbon mixture is affected by the capillary pressure and the surface forces and is different from that characterized in PVT cells. Many existing phase behavior models use a single pore size. This research investigates the effect of a pore size distribution on the phase behavior of hydrocarbon mixtures.

Pure n-pentane and a ternary mixture of n-butane, i-butane, and n-octane were loaded into a nanofluidic device with microchannels and nano-channels to study phase transition due to evaporation. For n-pentane, evaporation in the nano-channels took place immediately after the liquid in the micro-channels completely evaporated. For the ternary mixture, however, evaporation in the micro-channels slowed down and did not progress into the nano-channels despite continuous heating, because evaporation in the micro-channels changed the composition of the remaining liquid.

A vapor-liquid equilibrium calculation procedure that considers the effect of capillary pressure, the sequence of phase change due to pore size distribution and the associated compositional change was developed and used to simulate depressurization of light oil and retrograde gas inside nanoporous media. The pore size distributions were characteristic of tight reservoirs and the fluid compositions were representative of typical reservoir fluids. Predictions of the model show that phase transition in porous medium with pore size distribution is a process that cannot be described by a single phase boundary, because the initial phase change alters the composition of the remaining fluid, which in turn suppresses the next phase change. For the oil, capillary pressure due to nanoconfinement increased the level of supersaturation and the critical gas saturation had a strong influence on the properties of produced fluids; for the retrograde gas, the effect of capillary pressure was insignificant due to the low interfacial tension. Despite the choice of fluids, calculations indicate that the smallest pores are probably always occupied by hydrocarbon liquid during depressurization. Experiments and modeling presented in this research provide tools to investigate and understand the effect of nanoconfinement on phase behavior, which assist the development of shale oil and gas condensate reservoirs.
Effect of Fluid Rheology and Reservoir Compressibility on Microseismicity During Hydraulic Fracturing
Authors: Hosseini S. Mehran , Neuhaus Carl W. , Aminzadeh Fred
Published: October 2014

Microseismic monitoring, as an essential surveillance tool of hydraulic stimulation, enables the industry to optimize the development of unconventional reservoirs ranging from wellbore azimuth and wellbore spacing to completion and treatment design as well as providing a means for quality control and treatment efficiency evaluation. In order to correctly interpret microseismic data, a clear understanding of the mechanisms driving the generation of microseismicity is crucial. It is widely accepted and supported by full moment tensor inversion that microseismic activity associated with subsurface fluid injection is mainly caused by shear failure. Microseismic events can be separated into two main categories: near-field events and far-field events. Near-field events are the microseismic events close to the induced fracture (i.e. hydraulic fracture); as a result, the stress shadow effect (i.e. stress perturbation around a hydraulic fracture) is the dominant factor controlling such events. Far-field events are events that are not occurring in the vicinity of the tensile hydraulic fracture, hence the stress shadow effect is not the dominant phenomenon, but they are mainly controlled by pore pressure diffusion. Recent seismicity-based permeability characterization models couple fluid flow and reservoir geomechanics in order to capture microseismic mechanisms and calculate bulk reservoir-scale permeability. The same fundamentals were used in a forward modeling sense; by knowing reservoir properties we were able to predict the spatio-temporal distribution of microseismic activity. The effects of three parameters, including reservoir fluid viscosity, fracture fluid viscosity, and total reservoir compressibility were studied. Furthermore, the microseismic response of the reservoir in conjunction with instantaneous pump attributes was investigated. A physics-based model showed that increasing the viscosity of both reservoir and hydraulic fracture fluid will decrease the local extent of the propagation of the microseismic cloud. Studying the effect of reservoir compressibility showed that an increase in total reservoir compressibility decreases the local extent of the microseismic cloud. Results of the analysis were then used to explain observations made in field data and described in the literature.
Methodology of Well Productivity Prediction from Analyzing Formation Tester Probe Transient Pressure Data in A Multilayer Reservoir Using A New Spherical Drawdown Analysis Method
Authors: Alali A. Z. , Sheng J. J. , Soliman M. Y. , Watson M. C. , Ma S. M.
Published: October 2014

Single probe formation testers are widely used tools in the oil industry for collecting fluid samples and measuring pressure transients to estimate initial formation pressure. Although in principle pressure transient data can be used to estimate formation permeability based on drawdown and buildup analyses, the permeablity estimated is rarely used in reality since these estimation methods are based on a single-layer or homogeneous reservoir which is rarely the case. There are many probe test data available in the industry. If we can use these data to estimate permeabilities from every location the tool is stopped and upscale these permeabilities to predict the well productivity index (PI) for the whole multilayer reservoir, then these pressure transient data become very valuable. This can save the cost of or completely replace expensive well tests.

In this paper, we study the effect of the distance of outer layers on permeability estimation in multilayer reservoir systems. We first investigate the effective radius of drawdown and buildup tests of a typical probe test in a multilayer reservoir. Then we define a dimensionless parameter to present this effective radius. This dimensionless parameter is a function of permeability and the distance from the probe to the outer layer. Within this effective radius, the permeability may be estimated within an acceptable engineering error.

A new method is proposed to estimate the well productivity of a multilayer reservoir from single probe tests. The estimated well productivity is compared with that from the conventional well tests using simulated data as well as actual test data. The productivities from our test analysis technique and other approaches are acceptably close. Therefore, this effective dimensionless radius may be used to guide the selection of test locations so that the test data can be used later to estimate the PI of a well.
Global Component Lumping for EOS Calculations
Authors: Alavian Sayyed Ahmad , Whitson Curtis Hays , Martinsen Sissel O.
Published: October 2014

To reduce CPU time in compositional reservoir simulations, a minimum number of components should be used in the equation of state (EOS) to describe the fluid phase and volumetric behavior. A "detailed" EOS model often contains from 20 to 40 components, with the first 10 components representing pure compounds H2S, CO2, N2, C1, C2, C3, i-C4, n-C4, i-C5, and n-C5. The remaining components represent a split of the heavier C6+ material in single-carbon-number (SCN) fractions such as C6, C7, C8 and C9, or groups of SCN fractions such as C10-C12, C13-C19, C20-C29, and C30+. Occasionally the light aromatics BTX (benzene, toluene, and xylene isomers) are also kept as separate components for process modeling. Today's typical laboratory compositional analysis provides 50-60 components, including isomers with carbon numbers 6 to 10, SCN fractions out to C35 and a residual C36+. This is in contrast to the 11-12 components (through C7+) reported in most commercial laboratory reports pre-1980.

A "pseudoized" EOS model might contain only 6-9 lumped components – e.g. lumping "similar" components such N2+C1, i-C4+n-C4+i-C5+n-C5, and some 3-5 C6+ fractions. The selection of which components to lump together is difficult because of the huge number of possible combinations. This paper describes a systematic, automated method1 to search a vast number of feasible pseudoized EOS models based on an initial, detailed EOS model.

The obvious application of pseudoized EOS models is compositional reservoir simulation, where run time is an important issue and fewer components may be important. The method we present is based on (1) quantifying the "quality of match" between a pseudoized EOS model and the detailed EOS model from which it is derived, and (2) systematically testing all plausible lumping combinations. The method allows for a set of constraints to be imposed on the lumping of components, such as (1) not lumping certain non-hydrocarbons (e.g. CO2), (2) forcing the first plus fraction to contain a specific carbon-number component (e.g. C6), and (3) the last component in the original EOS not being lumped with other heavy fractions (e.g. C30+).

The proposed pseudoization procedure is comprehensive, and founded in the ability of an EOS with fewer components to describe a wide range of phase and volumetric properties covering all of the relevant pressure-temperature-composition (p-T-z) space expected for a given reservoir development. The litmus test of quality is how well the pseudoized EOS compares with the detailed EOS model from which it is derived, an EOS that accurately describes all key measured laboratory PVT data. The method proposed will find an optimal pseudoized EOS model to describe all PVT data that are relevant to a particular reservoir development – e.g. depletion performance, immiscible and miscible gas injection, compositional variation, and surface processing.
Flow Monitoring and Production Profiling Using DAS
Authors: in't panhuis Peter , den Boer Hans , van der Horst Juun , Paleja Rakesh , Randell David , Joinson Dan , McIvor Philip , Green Kevyn , Bartlett Richard
Published: October 2014

This paper discusses the application of DAS for flow monitoring. While previous publications (Van der Horst et al (2013, 2014)) focused on vertical and horizontal tight gas wells in North America, the focus here is on liquid producers and injectors in Brunei. Specifically, it was found that DAS has potential for zonal production and injection allocation across ICVs, monitoring interzonal inflow from the reservoir, monitoring artificial lift, tracking fluid transport through the well bore, detecting leaks, and monitoring wax build up or other types of deposition in the well.
Utilizing Oil Soluble Tracers to Understand Stimulation Efficiency Along the Lateral
Authors: Goswick Raven A. , LaRue Jon L.
Published: October 2014

Chemical water soluble tracers ("WSTs") have been routinely used in hydraulic fracture stimulations in attempts to verify and quantify load recovery from multi-stage stimulations. Load recovery is often interpolated with production data by assuming percent chemical recovered for a given stage directly correlates to that stage's production contribution. This assumption is often verified by a running production logging tools. New solid chemical oil soluble tracers ("OSTs") can now be utilized as a direct indicator of oil flow and production from deep in an individual stages’ fracture. Qualitative analysis gives an early "yes" or "no" to oil flow from each stage, while quantitative analysis may be achieved using relative concentrations of OSTs recovered, and reservoir and flow assumed conditions. OSTs may be used in conjunction with water soluble chemical tracers, or as a stand-alone tracer to determine oil flow from individual stages.

The purpose of this paper is to introduce utilizing solid particulate OSTs as a viable methodology to understand individual fracture stage oil contribution in horizontal wells. The results presented in this paper were derived from a three well pilot project performed in the Lower Marmaton formation in Roger Mills County, Oklahoma.

An investigation of hydraulic fracture stimulation efficiency was undertaken to determine if individual stimulation stages landed in either 100%, or only a portion of the pay sand, were contributing to the well's oil production. If so, to what extent? The reservoir pay thickness, along with the presence of second sand, influenced wellbore placement in that the drill bit can weave between the sands and the bounding shale layers. Also investigated was the magnitude the stimulation job had on offset producing wells. This was done by collecting and analyzing offset well production for the newly injected WSTs and OSTs. Preliminary results indicate offset communication between certain wells did occur, and the zones experiencing communication appear to have reduced contribution in the subject well's production.
Characterizing, Designing, and Selecting Metal Mesh Screens for Standalone Screen Applications
Authors: Mondal Somnath , Wu Chu-Hsiang , Sharma Mukul M. , Chanpura Rajesh A. , Parlar Mehmet , Ayoub Joseph A.
Published: October 2014

Discrete element method (DEM) simulations have proved to be valuable for selecting screens with simple geometries (e.g., wire wrap screens) under pre-pack test conditions (Mondal et al. 2011). Metal mesh screens (MMSs) (commonly referred to as premium screens) can have multiple (sometimes sintered) layers with different weave patterns. Any model for estimating sand production in such screens must account for these complexities. The objective of this paper is to explore different techniques to create accurate representations of complex filter media and to use them in numerical simulations and/or analytical models for improved screen selection.

In this paper, we have used computed tomography (CT) images of real screen coupons to construct 3D replicas of two MMS types: plain square mesh (PSM) and plain Dutch weave (PDW). An entirely computer-based method of creating 3D screen assemblies is also presented. The virtual screens have been compared and validated against the ones generated from the CT images. We have conducted DEM simulations of pre-pack tests through these multi-layer MMS assemblies. The retention efficiency of MMSs for different particle sizes has also been calculated for better slurry test modeling. We have shown that the effective size of MMS assemblies can be significantly lower than the nominal rating of the filter layer.

This paper augments the pre-pack test and slurry test models for mesh-type screens presented earlier (Mondal et al. 2012; Chanpura et al. 2013). Determination of the retention efficiency of MMSs, which is currently characterized by a single filter-cut point, is also a step forward in quality assurance and quality control of these screens. Finally, we demonstrate that indepth screen design and optimization studies can be conducted with virtual meshes in a consistent way and at a fraction of the cost and time that would be required otherwise using conventional experimental techniques.
Evaluation of a More Environmentally Sensitive Approach to Microbiological Control Programs for Hydraulic Fracturing Operations in the Marcellus Shale Using a Nitrate-Reducing Bacteria and Nitrate-Based Treatment System
Authors: Corrin Edward , Harless Michael , Rodriguez Chris , Degner Dennis , Archibeque Rodney
Published: October 2014

Control of micro-organisms during the completion of hydraulically fractured wells is a significant component in the successful development of a production system. Detrimental bacteria, such as sulfate-reducing bacteria (SRB), introduced into the reservoir during the completion process, can facilitate biogenic sulfide production, resulting in souring of the production fluids and gas, iron sulfide formation, and SRB associated microbiologically influenced corrosion (MIC). Biocides are routinely dosed at low levels into the fracturing fluids to control microbe populations and thus the subsequent adverse effects associated with bacterial activity. Biocides, by their very nature and intended purpose, are not well tolerated by certain aquatic organisms. In an effort to improve the ecological profile of the microbiological control program in fracturing operations, a treatment system using nitrate and nonhazardous live nitrate-reducing bacteria (NRB) for the control of SRB was developed.

Nitrate-based mitigation of SRB has been used as an alternative to biocide injection in the oil and gas industry for decades. Successful SRB control using nitrate-based treatment applications has been observed in several waterflooding programs throughout the world. Nitrates stimulate the metabolic activity of NRB. NRB can mitigate SRB activity by means of three primary mechanisms: competition for available carbon sources, direct metabolic inhibition through the generation of nitrite, and certain species of NRB, which directly oxidize biogenic sulfide. This case study is an evaluation of the application of live NRB, selected for their tolerance of the temperature and salinity of the Marcellus shale, and sodium nitrate nutrient solution, as an alternative treatment to the application of biocides for hydraulically fractured wells. Both live NRB and nitrate solution were added into the fracturing fluids during the fracturing operation.

Multiple wells were treated in the Marcellus shale using the tested NRB and nitrate treatment system, and these wells were monitored for periods ranging from three to 18 months depending on the date of completion. Treatment efficacy was evaluated by comparing data from the NRB and nitrate-treated wells to data collected from wells completed in the same manner and, in some cases, on the same well pad with a biocide that historically exhibited good microbial control. The results from the wells treated with NRB and nitrate demonstrated that the treatment was similarly effective compared to successful biocide applications for the control of SRB activity.
Pure and Coupled Drill String Vibration Pattern Recognition in High Frequency Downhole Data
Authors: Baumgartner Theresa , van Oort Eric
Published: October 2014

New high-frequency downhole recorders and high-bandwidth real-time data transmission tools (such as wired drillpipe) are heralding the era of big data in drilling. Nevertheless, high-frequency data is not yet used to its full potential, as the industry is only just beginning to make sense out of the many gigabytes of recorded data. Analysis of high-frequency data appears to be particularly useful to better characterize and understand vibration events, which are prominent technical limiters of drilling performance. The wealth of information provided by high-frequency vibration patterns, which are not present in low-frequency surface data, offers the possibility to significantly improve vibration mitigation methods. This, in turn, provides opportunities for step-changes in drilling performance improvement.

A simple kinematic model was developed to study the expected high-frequency acceleration measurement output under whirl and stick-slip vibrational dysfunctions. The vibration patterns predicted by the model matched the patterns observed in high-frequency field data very well, both in the time and frequency domain. The comparison reveals essential details of the downhole kinematics of vibrational modes, particularly regarding the nature of whirl, which may eventually lead to the development and application of novel whirl mitigation methods. Using the kinematic model, sensor measurements can be reproduced and thus fully understood, leading to sensor parameter and placement optimization. The match between modeled and field data also seems to show that the downhole high-frequency vibration patterns are apparently largely independent from specific operational parameters as well as borehole geometry. Moreover, vibration patterns appear to be more useful to classify and quantify vibration than absolute vibration parameter values.

Using the premise that vibration patterns hold the key to vibration identification and ultimately mitigation, a new methodology was developed and applied to extract and analyze essential features from high-frequency vibration data for identification purposes. Using a Bayesian approach with training supervised learning algorithms, vibrations were automatically classified with a success rate in excess of 90% when applied to high-frequency field datasets.
Graphical Determination of the Henry's Constant and the Diffusion Coefficient of Gases in Heavy Oils Using Late-Time Pressure-Decay Data
Authors: Pacheco Roman Francisco J. , Hejazi S. Hossein
Published: October 2014

Solubility and diffusivity of gases in heavy oil, respectively quantified by Henry's constant (Hij) and diffusion coefficient (D), are essential properties for the design of recovery processes that require the injection of gas or vapour solvents into the reservoir. Data, obtained from various experimental procedures such as the pressure-decay technique (PDT), are used to estimate these two parameters. The PDT uses a Pressure/Volume/Temperature (PVT) cell where the gas phase pressure declines as gas diffuses into heavy oil following an early-time and a late-time regime. Current approaches to analyze data from the conventional PDT are either graphical techniques based on early-time data or full numerical simulation. Early time data, the period in which the diffusing gas has not reached the bottom of the PVT cell, do not provide enough information to simultaneously estimate diffusion coefficient and Henry's constant. Hence, existing graphical procedures are limited to diffusion coefficient estimation.

In this paper, a novel and simple graphical technique is proposed to estimate the diffusion coefficient and Henry's constant using the late-time data from pressure-decay experiments. The proposed method is based on modeling of gas phase pressure decay using Fick's second law and gas phase mass balance equations. The Integral method is used to provide an approximate, but analytical solution to the set of equations. The resultant solution is used to develop a simple graphical method, i.e. inverse problem, in which both diffusion coefficient and Henry's constant are directly estimated. The estimated parameters through the proposed technique for methane/bitumen and carbon dioxide/bitumen experiments are in close agreement with the values reported in the literature.
An Innovative and Systematic Approach to Delivering a Multitude of Next Generation Tubular Connections Required for Extremely Complex Design Conditions
Authors: Japar Nor Janiah , Grant Lisa , Van den Haak Arno , Duhe Jason , Terrill Grant , Smith Larry D.
Published: October 2014

New regulatory requirements and design conditions introduced in recent years have led to the use of higher strength tubulars in the majority of Deepwater wells in the Gulf of Mexico. To achieve the new design requirements, the use of non-conventional casing sizes, grades and weights different than those traditionally used and available in the industry are required. The use of thicker wall tubular has consequently resulted in geometrical constraints and tighter annuli clearances in the wellbore driving new connection design requirements and selection criteria to meet overall well objectives. The new design conditions require innovative connection design to meet or exceed the collapse strength of pipe body rating. As part of the Shell Mars B project, the Olympus TLP DVA team championed the development and qualification of multiple connection types to meet the project requirement and for overall portfolio usage. As the number of connections to be designed and qualified is substantial, a pragmatic and systematic testing philosophy and strategy was developed for the Mars-B project TLP DVA wells.

This paper provides a high level overview of the connection selection challenges, the systematic process adopted to streamline connection development, testing and qualification. It will also discuss some of the challenges in connection design to meet well requirements and qualification process. The scope includes static connection design for strings installed below the subsea well head, as well as, dynamic connection design on strings that are installed in the water column. Both connection designs require sealability qualification and assurance. Dynamic connections require additional fatigue design and qualification. Rigorousness of sealability and fatigue testing is appropriate to the environment of which it will be subjected throughout the well and the 50 year field life.
An Effective Coupling of Type Curves and Expert Systems for Evaluating Multi-stage Hydraulically Fractured Horizontal Wells in Composite Dual-porosity Shale Gas Reservoirs
Authors: Siripatrachai N. , Rana S. , Bodipat K. , Ertekin T.
Published: October 2014

To unlock natural gas from shale, placing horizontal wells equipped with multi-stage hydraulic fracturing is crucial. Due to complexities and uncertainties of formation characteristics and stimulation design parameters, field optimization studies can be challenging. In addition, several models for hydraulic fracturing have been proposed. However, equivalency criteria between models have not yet been fully understood. In this paper, we propose a new approach to tackle some of these challenges through the coupling of type curves and artificial neural network based models. The complete framework and results of type curves and ANN-assisted prediction of equivalent systems are shown and discussed. The first part of the work will focus on ANNs for establishing equivalencies between different hydraulic fracture representations. ANNs which are powerful tools capable of establishing relationships between highly non-linear parameters have been developed to assist numerical reservoir simulations in predicting production profiles and establishing equivalencies between two hydraulic fracture representations for a wide range of parameters describing various systems. The equivalent systems yield overall production profiles and cumulative productions within ±15% discrepancy between the two hydraulic fracture representations at the end of the simulation. In the second part of this work, analysis of pressure transient drawdown data through the developed type curves coupled to ANNs is performed. The pressure transient analysis enables us to obtain key properties of the stimulated zone and identify the more probable equivalent systems. The crushed zone properties are then used in the developed ANNs. The ANNs can instantly predict gas production rates as well as establish its equivalent transverse hydraulic fracture representations. Another ANN is then used to predict gas production rates based on the predicted transverse fracture parameters. The results show that gas production rates and cumulative production from ANNs and numerical model based on parameters predicted by type curves are in good agreement with the base case. This proposed unique approach through the coupling of type curves and ANNs can assist in analysis and reservoir simulation studies for optimization of shale gas development projects in a rapid manner.
Optimal Hydraulic Fracture Angle in Productivity Maximized Shale Well Design
Authors: Sorek Nadav , Moreno Jose A. , Rice Ryan , Luo Guofan , Ehlig-Economides Christine
Published: October 2014

In general, hydraulic fractures propagate perpendicular to the horizontal well axis whenever the drilling direction is parallel to the principal minimum stress plane. However, operators frequently drill horizontal wells parallel to lease boundaries resulting in slanted hydraulic fracture planes at angles less than 90 degrees from the well axis.

This study provides a model for the inclined fracture case. It applies and further extends the unified fracture design approach for rectangular drainage areas, relating the dimensionless proppant number to the maximum productivity index in pseudo-steady state conditions. When simulating flow in shale reservoirs, the stimulated shale volume was represented as a rectangular drainage area that varies with changing angle, but preserves total area. Similarly, fracture length and width varies with changing angle, but total propped fracture volume stays constant.

Results show that for any given set of reservoir and proppant properties along with a given proppant mass, as long as the created fractures drain the same stimulated rock volume, there exists a well direction resulting in maximized well productivity that is not necessarily parallel to the minimum stress direction.

In addition, results yield two main correlations. The first one relates the optimal fracture angle to proppant number, for a given ratio of well spacing to primary-fracture spacing. In this way, operators can choose the drilling azimuth that would maximize production. The second correlation determines the optimal ratio of well spacing to primary-fracture spacing as a function of proppant number for a given fracture angle. This can be applied when selecting the optimum number of fracture stages given a well spacing plan and fracture angle. Two case studies show the application of these findings. In the end, this work provides a simple framework for well design incorporating slanted hydraulic fractures.
A Trilinear Flow Model for a Fractured Horizontal Well in a Fractal Unconventional Reservoir
Authors: Ozcan O. , Sarak H. , Ozkan E. , Raghavan R.
Published: October 2014

Based on the premises of anomalous diffusion models in fractal porous media, an alternative to dual-porosity based formulations of flow in fractured unconventional reservoirs is presented. The new formulation is implemented in the trilinear flow idealization for a fractured horizontal well in a tight formation and verified by using the asymptotic cases. The results of the new model are compared with the dual-porosity based trilinear flow formulation and the differences and similarities are delineated. A discussion of the characteristics of the pressure and derivative responses obtained from the trilinear anomalous-diffusion model is provided and related to the fractal nature of fractured media. Physical interpretations are also assigned to fractional derivatives and the phenomenological coefficient of the fractional flux law. It is shown that the anomalous diffusion formulation does not require explicit references to the intrinsic properties of the matrix and fracture media and thus relaxes the stringent requirements used in dual-porosity idealizations to couple matrix and fracture flows. The trilinear anomalous-diffusion model should be useful for performance predictions and pressure- and rate-transient analysis of fractured horizontal wells in tight unconventional reservoirs.
Technical Data Management – Standards and Replication for Enabling Increased Production from Global Assets
Authors: Bhan Sushma K.
Published: October 2014

Technical Data Management (TDM) is an integral part of the global Wells, Reservoir, and Facility Management (WRFM) program in Royal Dutch Shell, plc, aiming to maximize production from existing global assets. WRFM data is wide-spectrum in nature, ranging from subsurface to wells development, facilities, production and reservoir engineering data. Managing this wide spectrum data is important for WRFM success and requires addressing bottlenecks at both local and global levels. The various data challenges encountered in upstream assets can be categorized under the following: a) technical data is often hard to access, scattered and in non-standard data repositories, b) lack of robust discipline data ownership like Well Engineering, Reservoir Engineering, and Production Technology with well defined data management plans or c) inconsistency in data types and quality managed within assets. The above mentioned issues are being addressed by: 1) the development and implementation of the WRFM Standard TDM Plan for assets bringing further consistency in managing data, 2) the use of WRFM Critical Data Catalog to ensure all assets have consistency in managing the same minimum discipline data and data types and 3) the development of minimum data standards for additional data types to further enable replication efforts with a standardized approach.

The WRFM Standard TDM Plan was first piloted in three assets to validate the standardized data support plan in the assets from heavy oil to deep water lines of business. The standard TDM plan deployments are now being replicated across other assets to bring further data management standardization, data consistency, tracking of Data Quality (DQ) measurements, and improvements in quality assurance with guidance from discipline data owners as well as Global Discipline Heads, Principal Technical Experts and Subject Matter Experts.

The WRFM Critical Data Catalog serves as a standard list of data to manage, included in the plan's implementation with traffic lights to measure and track the continuous improvements within specified periods. Minimum standards for data — for example PVT (Pressure Volume Temperature) standard, endorsed by the reservoir engineering as well as the Technical Data Management disciplines — ensures this valuable reservoir engineering data is stored in the corporate store, versus an ad-hoc local solution, thus providing easy access of this data and supporting replication of DQ assessment/assurance mechanism globally.

The impact of the above technical data management efforts are evident in several assets, where data management scores are improving from the past measurements, also resulting in assets being ahead on their production plans, enabling additional barrels with efficiency gains and timely decision making. This paper presents the Technical Data Management journey on global WRFM data assets within Shell aimed at providing reliable data at engineers' and geoscientists' finger tips and value-add to the business.
Estimating Drillpipe Body Wear to Improve Drilling Performance in Challenging Shale Plays
Authors: Kumar Aniket , Samuel Robello , Granger Scott
Published: October 2014

The recent advances in drilling activities in shale plays have led to unprecedented challenges that need to be addressed to improve the drilling performance. One of the challenges, experienced especially in the Bakken formation, is a very high rate of drillpipe body wear. The drillpipe body wears out more quickly than the tool joints, thus reducing the life of the tube. Consequently, a mechanism to analyze the pipe body contact would be useful in understanding the downhole scenario and would help to reduce the wear.

This study uses the finite element analysis to perform a step-by-step investigation of the drillpipe body wear during the drilling of a typical Bakken well using field data. The model helps to calculate the clearance of the center of the pipe body from the wellbore for each joint of pipe and further estimates the side force if there is any contact. The side force analysis is then used to predict the downhole wear in the pipe body under the given drilling parameters.

The field case study presented compares the performance of 4-in., 4¼-in., and 4½-in. drillpipe from the kickoff point in the 8¾-in. build section. It also analyzes the 4-in. and 4¼-in. drillpipe in the 6-in. lateral section to the target depth. The study also critically examined the influence of drilling parameters on pipe performance to better understand downhole conditions. Based on this analysis, recommendations are provided to mitigate drillpipe body wear for shale drilling environments. This study has the potential to be fully implemented to improve the drill string design in shale plays to reduce drilling times, increase drilling efficiency, and reduce costs by maximizing the life of the drillpipe.
Long Term Effect of Natural Fractures Closure on Gas Production from Unconventional Reservoirs
Authors: Aybar Umut , Eshkalak Mohammad O. , Sepehrnoori Kamy , Patzek Tad
Published: October 2014

Observed trends of long-term production forecasts of unconventional assets tend to secure US energy supply for decades to come. Also, recent innovations in horizontal drilling and hydraulic fracturing support such trends to be economically viable. However, triggered fractures in an unconventional reservoir rapidly shrink and will result in significant long-term production loss. Hence, it is essential to quantify the effect of fracture closure on long-term production. In this paper, the permeability changes of secondary fracture network are investigated with respect to the effect on the long-term gas production from unconventional reservoirs.

A simple analytical trilinear model is improved in order to handle the constant bottom-hole pressure production and analyze the cumulative gas production by considering the effect of stress on natural fracture permeability. Moreover, a sensitivity study is performed to identify the influence of uncertain parameters on cumulative production and consequently detect a condition in which the pressure-dependent natural fracture effects on production are severe.

It is observed that the pressure-dependent natural fracture permeability can cause up to ten percent less cumulative production than the constant natural fracture permeability conditions. The improved analytical model is very fast compared to the commercial numerical simulators. The advantage of this approach is in obtaining a quick and accurate assessment for operators in the pre-evaluation process of the complex production behavior of their unconventional resources. The findings of this paper provide insights into long-term investment of unconventional reservoirs and guide decision making for the secondary or tertiary enhancement treatments of unconventional wells, such as re-fracturing.