bluuebunny/crossref_metadata_2025 huggingface dataset:
Simulation of Flow and Dispersion on Pore-Space Images
Authors: Mostaghimi Peyman , Bijeljic Branko , Blunt Martin J.
Published: February 2011

We simulate flow and transport directly on pore-space images obtained by micro-CT scanning of rock cores. An efficient Stokes solver is used to simulate low-Reynolds number flows. The flow simulator uses a finite-difference method along with a standard predictor-corrector procedure to decouple pressure and velocity. An algebraic multigrid technique solves the linear systems of equations. We then predict permeability and the results are compared with lattice Boltzmann numerical results and available experimental data.

For solute transport we apply a streamline-based algorithm that is similar to the Pollock algorithm common in field-scale reservoir simulation, but which employs a novel semi-analytic formulation near solid boundaries to capture, with sub-grid resolution, the variation in velocity near the grains. A random walk method accounts for molecular diffusion. The streamline- based algorithm is validated by comparison with published results for Taylor-Aris dispersion in a single capillary with a square cross-section. We then accurately predict available experimental data in the literature for longitudinal dispersion coefficient as a function of Peclet number. We introduce a characteristic length based on ratio of volume to pore/grain surface area that can be used for consolidated porous media to calculate Peclet number.
Application of Particle Swarms for History Matching in the Brugge Reservoir
Authors: Mohamed Linah , Christie Mike , Demyanov Vasily , Robert Emmanuel , Kachuma Dick
Published: February 2011

Reservoir modelling is frequently used in the oil industry to measure the risk associated with alternative production scenarios. However, reservoir models themselves contain a high level of uncertainty because of the typically very limited, sparse and multi-scaled reservoir knowledge. The effect of this uncertainty can be assessed by producing a set of diverse models that match the production data reasonably well and using these models to quantify uncertainty in predicting the future performance of the reservoir.

Evolutionary and swarm intelligence algorithms have become very popular for history matching due to their simplicity and parallel implementation capacity. This paper focuses on the application of Particle Swarm Optimisation (PSO) for history matching the Brugge field (a recent SPE benchmark case study). The parameterisation of the model is based on principal component analysis (PCA) for modelling spatially correlated random fields (e.g. porosity, net-to-gross and permeability) applied to the set of initial realisations which describe the range of prior beliefs. The PSO is then used to find the set of possible combinations of parameters, represented by the PCA eigenvalues, which match the historical data and honour the static data from the wells present in the initial realisations.

We show that PSO is able to find multiple good and diverse history matched models for the Brugge reservoir without exhaustive sampling of the parameter space. Uncertainty of production forecasts are quantified by P10-P50-P90 uncertainty envelope obtained from the ensemble of PSO models. The history matching results are compared with the ones obtained with Ensemble Kalman Filter data assimilation method. These results show the ability of PSO to handle large history matching problems and obtain results comparable to the EnKF for this case study.
Advances in Openhole Packer/Sleeve Completions Coupled With Multilaterals Provide Cost-Effective Solutions
Authors: Johnson C. Christopher , Courrege David W.
Published: February 2011

The Bakken Shale located in North Dakota has seen large increases in oil and gas production. The contributing technologies that have aided in the increased production are the recent advances in openhole packer and sleeve completions. These completions have enabled operators to isolate and fracture up to 24 stages using a one-trip openhole packer and sleeve completion.

The use of multilaterals enables operators to save capital investment by accessing production from two laterals while chilling a single vertical wellbore. Greater drainage access across a section is also achieved by using this technology. Coupling multilateral and openhole packer/sleeve technologies together allows for multiple-stage hydraulic fracturing operations of both laterals.

This paper will show how employing openhole packer and sleeve completions coupled with a fracturable multilateral junction provides a cost-effective way to drill, complete, and stimulate wells in the Bakken. The experience gamed in the Bakken will be applicable worldwide as operators look to optimize openhole completions in their unconventional reservoirs.
Preparing for the Crew Change - Gearing Up Women to Spud In
Authors: Williams John M. , Lau Laura J. , Lau Richard A.
Published: February 2011

The late president of the United Arab Emirates, Sheikh Zayed Al Nahyan, insisted that women participate fully and equally in its growth and prosperity. In 2006, the Abu Dhabi National Oil Company (ADNOC) invited women to join their petroleum engineering educational program and study on a par with their male counterparts. ADNOC is already planning to incorporate the first female graduates into their operating companies in 2011, but are women receiving the same level of instruction as men? To help find out, the researchers initiated a study collecting data from more than 600 students over five semesters, ranging from educational background, gender, grade point average, and choice of engineering major. In addition, student and faculty surveys were conducted attempting to assess opinions about the courses, the instructors and the students.

The study highlights that female employment issues are an increasingly important subject in the U.A.E. and two reasons are proposed why more women are opting to study for professional positions in the oil and gas industry.

Data for student performance at the Petroleum Institute show that females are achieving almost identical academic results to males. Analysis of the wide-ranging survey data draws conclusions as to whether women will be able to compete effectively with men. The variety of attitudes to female engineers in the oil industry is presented. A significant proportion of male students reported major reservations about hiring and working with female engineers.

This study demonstrates the benefits of cooperation between language and engineering faculty and concludes that fast track changes in gender diversity require commitment and changes in attitude from political leaders, oil companies and young engineers. The study will be of great interest to national oil companies, and other petroleum organizations aiming to increase use of nationals, and to all companies considering expanding opportunities for female engineers as part of a response to the changing demographics in the oil industry, commonly known as the crew change.
Reservoir Modeling: From RESCUE To RESQML
Authors: King Michael J. , Ballin Paulo , Bennis Chakib , Heath David , Hiebert Allan , McKenzie William , Rainaud Jean-Francois , Schey Jana
Published: February 2011

The RESCUE consortium formed in 1995 in response to the requirement to transfer the structural framework, 3D gridded models, and associated well data from "geomodels to upscalers". RESCUE developed a data standard and libraries which allowed multiple vendors to support subsurface projects across the geoscience and engineering domains. To date, over 20 of the sponsoring petroleum companies and application vendors have integrated RESCUE into their applications.

In late 2008 the consortium began a transition to a much more flexible standard: RESQML™. RESQML joins with WITSML™ and PRODML™ as the latest XML-based data transfer standards managed by Energistics. Simple prototype models have already been transferred using RESQML; we expect commercial application in the next 12-24 months.

RESQML has been designed to support:

Interaction with the real-time production and drilling domains; Transfer of giga-cell reservoir simulation models, as are currently in use in some areas of the world, with static reservoir models which may be several orders of magnitude larger; Loss-less data transfer for complex grids, especially for non-standard connectivity; Retention of the geologic and geophysical meta-data associated with 3D grids; Data standards for flexible and iterative multi-vendor subsurface workflows across geology, geophysics and engineering.

As an example of the latter, workflows that support fault seal analysis or 4D seismic interpretation benefit greatly from the integration of data, meta-data and interpretations from multiple geophysical, geologic and engineering applications into a coherent subsurface model. Such integration is not possible for a single application or vendor.

In this paper, we will present our objectives, challenges and work plan for 3D/4D reservoir model exchange. Details of the technical design defined by participating oil companies and software vendors will be shared to demonstrate the efficiency of the RESQML standard.
Experimental Research of Work of Different ESP Stages on Viscous Fluids
Authors: Mokhov Mikhail , Tsunevskiy Andrey
Published: February 2011

Recent years there is trend of oil production increase from the wells with abnormal operating conditions. One of the complicated factors is elevated viscosity of the oil well production. Selection of the high-performance equipment for the work in such conditions is nowadays very relevant. The purpose of this research is a comparison of work of different construction ESP stages on the viscous fluids.

Tests of work of Different ESP Stages were hold on the experimental bedstead of Oil Field Development and Exploitation Department of Gubkin University. Tested ESP Sections are shown in Figure 1.

The following ESP stages were used as a subject for comparison: production stage VNN5-125, production stage VNN5-125 with bored impeller blades, and new construction stage with open-type impeller, which was developed at the Oil Field Development and Exploitation Department of Gubkin University.

Industrial glycerin was used as a viscous working fluid. Viscosity of glycerin has been changed in accordance with different concentration of water in the solution, and variation of temperature of the flow in different production conditions as well.
Using Maps of Microseismic Events to Define Reservoir Discontinuities
Authors: Craig David P. , Burkhart Roger
Published: February 2011

Multidirectional linear trends are commonly observed in maps of microseismic events recorded during fracture stimulation. Since Fisher drew lines through an animated map of microseismic events (Fisher et al. 2002), the industry has recognized that complex-fracture patterns can develop during hydraulic fracturing. Consequently, several new complex-fracture propagation models have been introduced to "match" the stimulated reservoir volume observed in maps of microseismic events recorded during hydraulic fracturing.

Every complex-fracture propagation model requires geometric input, including a pattern of discontinuities in the rock that can dilate or propagate during hydraulic fracturing; however, defining a pattern of discontinuities is a challenging task in a subsurface rock formation that cannot be observed directly.

We present a new method for defining a geometric model for input into a complex-fracture model using microseismic events recorded during fracturing. Events are animated and planar trends are identified to define natural fracture orientation, trace length, dip angle, and natural fracture density within the stimulated reservoir volume. Statistical analysis of the natural fracture properties allows probability distributions to be defined for each fracture property, which are then used to generate stochastic natural fracture patterns for input into a complex-fracture model.
Joint Inversion of Cross-Well Electromagnetic and Seismic Data for Reservoir Petrophysical Parameters
Authors: Gao Guozhong , Abubakar Aria , Habashy Tarek
Published: February 2011

Accurate determination of reservoir petrophysical parameters is important for formation evaluation and reservoir management. In this paper, we present a joint inversion approach for the estimation of reservoir petrophysical parameters, such as porosity and fluid saturations, from electromagnetic and seismic measurements. Electromagnetic data are linked to porosity and fluid saturations through Archie's equations, while seismic data are linked to porosity and fluid saturations through a rock physics fluid substitution model. The approach provides substantial advantage for an improved estimation of porosity and fluid saturation distribution over the one obtained from the separate inversion of electromagnetic and seismic data. Sensitivity studies combined with inversion tests show that seismic data are mainly sensitive to the porosity distribution, while electromagnetic data are sensitive to the fluid saturation distribution. The inversion of either electromagnetic or seismic data is not unique, and thus leading to ambiguity in the determination of porosity and fluid saturations. We show that the joint inversion approach reduces the ambiguity on the determination of porosity and fluid saturations, thus leading to improved reservoir characterization. The concept and the implemented inversion method are demonstrated using various cross-well survey examples.
Application of Air Percussion Drilling Improves Drilling Efficiency in Horizontal Sandstone Wells
Authors: Pletcher Joe , Scarr Adam , Smith Jeremy , Swadi Shantanu , Rogers Clint
Published: February 2011

EQT Production has implemented a new technique for drilling horizontal wells in the hard formations of the Appalachian Basin. Air percussion drilling has been adopted for use horizontally in the Berea sandstone, a hard and abrasive sandstone reservoir that had been traditionally drilled with roller cone bits. The evolution of the technology started with a packed-hole assembly that was trialed on three wells using stabilizer placement to provide directional control in the horizontal. The results were promising as penetration rates increased, but many trips were required to keep the wellbore in the desired target zone. To improve directional control, a percussion BHA with a bent housing positive displacement motor (PDM) was implemented. The introduction of the positive displacement motor with the air hammer produced the same penetration rates seen in the packed-hole assembly while providing the directional control needed. Since mid 2009, the PDM percussion assembly has become the standard practice for drilling Berea horizontal wells, replacing the roller cone BHA. Through June 2010, over 40 wells have been drilled using the assembly. The lateral portion for a majority of the wells is now drilled in one run, reducing total drilling time from 22 to 13 days, dry hole costs by over one half and total well costs by about one third.
Lessons Learned Implementing Step-Change Technology on the Latest Generation Deepwater Drillship
Authors: Ruths Mark
Published: February 2011

Two of the greatest opportunities to increase value in drilling today are improving drilling efficiency and reducing Non Productive Time (NPT). A new sensor technology was developed to make step-change progress on both these opportunities. A new sensor and data integration and analysis system was implemented on one of the world's most advanced drillships. This paper presents the challenges and lessons learned that were experienced during deployment and first use of this technology, many of which can point the way to implementing other new technologies on advanced drillships.

This technology is specifically designed to give the driller, DSM and office personnel the most integrated view of all the data needed to fine-tune drilling efficiencies, warn of impending events and take evasive action to prevent and minimize them, thereby reducing NPT. To accomplish this, the data is presented in easy-to-digest displays on a web browser securely accessible from anywhere.

This technology, which is the subject of several pending patent applications, includes new technology which includes new ways to measure real time flow rate, volume and other mud properties. With continuous refinement, this technology offers the industry a step-change in drilling efficiency and NPT reduction and provides a platform upon which other sensors can be easily tested and evaluated.

This paper focuses on the challenges and lessons learned in piloting this new technology on an advanced generation drillship in an accelerated manner to reap value soonest.
Biogenic Gas Generation From Shallow Organic-Matter-Rich Shales
Authors: Cokar M. , Kallos M. S. , Huang H. , Larter S. R. , Gates I. D.
Published: February 2011

Understanding both physical and biological processes of gas generation and movement in immature organic matter rich shales is essential to optimize gas production from this resource. As yet, there is no complete description that accounts for the many gas transport modes in these systems. Field production data reveals that gas production from these reservoirs declines initially and then stabilizes after a specified time. The stabilized rate is controlled by the contributions of biogenic gas generation, desorption of gas from kerogen, diffusion and transport of gas through nanometer to potentially even micron scale pore systems in coarser grained intervals where physics of transport differ in mechanism. One factor that is ignored is the biogenic gas generation rate and whether this is significant in recharging the resource during a resource well lifetime. This paper presents a modified gas material balance to account for biogenic gas generation. The results of the theory are then compared to gas production data obtained from a shallow shale reservoir in Western Canada. Production from biogenic shale gas reservoirs tends to be at low rate but is stable over extended periods of time. However, it is not yet well understood what the dominant gas transport mechanisms are so that production from these reservoirs can be improved and optimized. Although the gas material balance approach is well established, it has not been used to constrain biogenic gas generation rates. The analysis conducted in this research can be used to optimize productivity from these fields. The new theory helps reveal the key physical controls on gas production from organic shales and means to enhance it. The theory developed in this study is novel and significant because it further develops the underlying theory for biogenic gas transport and production from organic shales, a potentially massive gas source in Western Canada and worldwide.
Changing the Shape of Fracturing: New Proppant Improves Fracture Conductivity
Authors: McDaniel Greg , Abbott Jonathan , Mueller Fred , Mokhtar Ahmed , Pavlova Svetlana , Nevvonen Olga , Parias Thomas , Alary Jean André
Published: February 2011

Hydraulic fracturing is used extensively to increase hydrocarbon production from oil and gas formations. Hydraulic fracture conductivity is a key parameter in optimizing the productivity of a well after the fracture treatment. The American Petroleum Institute (API) proppant permeability / fracture conductivity testing results are frequently used in industry fracturing models when selecting the proppant that provides the optimum fracture conductivity for a well's particular reservoir properties. This design methodology invariably results in a lower than expected fracture conductivity and in many cases, lower than optimum well performance. The industry has recognized that actual fracture conductivity is often a small fraction of what would be expected by using API test results. Non-Darcy flow, multiphase flow, gel damage, stress cycling, fines migration, proppant embedment, proppant flowback, and fracture cleanup are some of the parameters that result in fracture conductivities significantly lower than those measured in an API conductivity test.

A new proppant was developed to improve the final fracture conductivity achievable with high-strength spherical proppants currently available in the market place. This new product is an elongated rod-shaped, high-strength particle with integrated proppant flow back control.

Initial field testing of the product was conducted in moderate permeability formations where production from prior fracture treatments indicated lower than optimum fracture conductivity. Production results from these field tests confirmed that substantial increases in fracture conductivity can be achieved. The large improvement seen in fracture conductivity can be attributed to increased porosity of the proppant pack and reduced fracture conductivity losses due to non-Darcy and multiphase flow effects.

Completely changing the typical geometry of proppants used in hydraulic fracturing is a viable option for improving the conductivity of hydraulic fractures to a point not currently obtainable with spherical proppants.
Dynamic Network Modeling of Resistivity Index in a Steady-State Procedure
Authors: Tørå Glenn , Hansen Alex , Øren Pål-Eric
Published: February 2011

We present numerical results of electrical resistivity of two-phase flow in reservoir rocks using a dynamic network model. The model accounts for viscous and capillary forces, as well as wetting layers in the crevices of the pore space. It can be used as a unified model for drainage, imbibition and steady-state displacement.

We use the model to study viscous effects on electrical resistivity for two-phase flow under strongly water-wet conditions. The pore network is extracted from a realistic pore space of a sandstone. For unsteady drainage and imbibition, our numerical results display capillary number dependent non-Archie behavior and hysteresis of the resistivity index. For steady-state displacement the resistivity index exhibits no significant hysteresis. For increasing capillary number we observe a higher degree of non-Archie (negative curvature) behavior. The simulated data are compared with relevant experimental data, and are in good agreement.

Our conclusion is that the dynamic network model successfully reproduces viscous effects on the resistivity index in drainage, imbibition and steady-state displacement processes.
Comparative Study of Cemented Versus Uncemented Multi-Stage Fractured Wells in the Barnett Shale
Authors: Lohoefer Darrell , Snyder Daniel J. , Seale Rocky , Themig Daniel
Published: February 2011

The industry has made a very quick turn toward both unconventional reservoirs and horizontal, multi-stage fracturing. Some industry experts have begun to question the effectiveness of recoveries in these massive reserve assets. A notable formation in these discussions has been the Barnett Shale, where a variety of methods and technologies have been used to fracture stimulate horizontal wells. In fact, much of the learning curve for completion practices has come from experimental work in this unconventional play.

From 2004 through 2006, a new, open hole, multi-stage system (OHMS) completion technology was run in Denton County, Texas. Using publically available data from the past five years, this study contrasts long-term production results from OHMS completed wells and wells completed with cemented casing.

The data set for OHMS fractured wells compared to the data set for cemented fractured wells indicates that open hole wells, on average, performed better. Significantly, no failures or shut-in periods were observed for the OHMS wells. This establishes the viability, reliability and effectiveness of this technology for the long-term life of wells not only in the Barnett, but for performance enhancement in other shale plays.

Substantial amounts of money are currently being spent to rapidly develop resource plays similar to the Barnett worldwide. Based on short-term results using current completion methods, predictions for ultimate recoveries may be overestimated. This paper evaluates the effectiveness of current completion practices by contrasting two methods in terms of production, economics, operational efficiency, and best fracturing practices to determine whether the completion method can affect overall well performance and long-term recovery.
A Technical and Economic Study of Completion Techniques in Five Emerging US Gas Shales
Authors: Agrawal A. , Wei Y. , Cheng K. , Holditch S. A.
Published: February 2011

With the increased demand for energy and the declining conventional hydrocarbons worldwide, energy companies are turning to unconventional resources, such as shale gas. With over 2, 000 TCF gas in place indentified in just 5 shale gas plays in the United States, shale gas formations are now the number one targets for exploration drilling. Furthermore, there are still many more major shale gas plays and basins waiting to be explored, evaluated and developed. Because of the extremely low permeability of most shale formations, it is essential to select the appropriate completion techniques for shale gas reservoirs. There are very few papers in the petroleum literature that provide a logical method to select completion techniques for given shale gas reservoir conditions. There are papers discussing successful completion techniques that seem to work for a specific shale. We have used many of these SPE papers to help define "best-practices" in completing shale gas reservoirs. We then developed logic to determine the best practice on completing shale gas reservoirs as a function of reservoir conditions. In this paper, we will specifically cover the logic we have developed for choosing completion techniques on shale gas reservoirs.

First, we performed a literature review on the five basins as well as on all shale gas plays in the U.S. to determine the best practices in shale gas completion techniques in fluctuating price environments and identify key geologic parameters that affect overall well performance. From our literature review, we identified seven pertinent geologic parameters that influence shale gas completion practices. Next, we identified different completion trends in the industry for different geologic settings. Subsequently, we generated an economic model and performed sensitivity analysis to determine optimal completions for each gas shale basin. Based on these economic models, we developed the decision flowcharts to select completion techniques. Finally, we programmed the flowchart and we call this program as Shale Gas Advisor. This program can be used to determine optimum completion best practices for not only the five gas shale basins discussed, but also, for gas shale plays that have similar geologic attributes. We validated the program with published case histories in the SPE literature.
Method of Establishing Vibration Limits and Determining Accumulative Vibration Damage in Drilling Tools
Authors: Wassell Mark , Stroehlein Brian
Published: February 2011

MWD tool life is affected by its operating environment. High vibration, shock and temperature reduce the life of the tool. This paper presents a method for combining vibration, shock and temperature effects to calculate MWD tool life.
A Decision Analytic Framework for Autonomous Geosteering
Authors: Rajaieyamchee Mohamad A. , Bratvold Reidar B.
Published: February 2011

One of the objectives of Integrated Operations (IO)1 is to automate the decision-making process in drilling operations. Such automation is essential to improve both decision quality and speed in the complex and data-rich environment of drilling operations.

Over the past decade, the E&P industry has significantly improved its ability to acquire and share large data volumes at unprecedented speeds. The motivation for these investments is to increase value through increased future productions while simultaneously reducing drilling costs. However, utilizing the large data volumes is not always straightforward. Sensor measurements are uncertain because of their reading errors and possible malfunctions, and many sources of data need to be fused to provide decision-relevant information. Furthermore, many drilling operational decisions must be made with very limited time, and this makes evaluating potential alternatives based on the decision criteria by the geosteering team difficult or even impossible. Given these challenges, there is a need to develop efficient processes and tools to automatically support drilling operational decisions.

In this paper, we propose a modular intelligent decision advisor (IDA) framework for supporting geosteering decisions. The first module validates and combines the sensor data to determine the probability of the sensor faults and failures as well as undesired geosteering events. These events may include a dramatic increase in drag friction factors, approaching bed boundaries, tools damage, etc. Failure to detect these events could lead to losing the steering ability and sometimes catastrophic problems. The second module proactively analyzes geosteering hazards and recommends the best alternatives. To perform the sensor validation/fusion and hazard/decision analysis, we suggest the use of influence diagrams, also known as Bayesian decision networks (BDNs).

Developing an IDA can lead to the reduction of human operators from rig-sites, drawing its value from improving the human safety and geosteering efficiency. Implementing IO with its associated technologies such as large volume data transmission and computational capabilities provides the means for this autonomous decision advisor. Our results show that the BDN is a useful and relevant element in the autonomous geosteering decision-making process.
Petroleum Engineer or Energy Engineer: Should We Be Both?
Authors: Battalora L. A. , Graves R. M. , McNeil J. A.
Published: February 2011

Each year hundreds of petroleum engineering graduates enter the oil and gas industry workforce eager to confront the challenges presented by worldwide supply and demand. As industry expands its mission to include clean energy, have we adequately prepared our new graduates to address the complex role of global energy consumption and its impact on the oil and gas industry?

An education model exists at the Colorado School of Mines (CSM) to enhance the undergraduate curriculum in the discovery, production and use of energy. An 18-credit Energy Minor addresses the scientific and technical aspects of energy production and consumption in tandem with economic, environmental and societal impact. In a multidisciplinary environment, students investigate the production, delivery, and utilization of fossil, renewable and nuclear energy as it relates to current and future domestic and global requirements and concerns.

The Energy Minor at CSM involves multiple departments on campus. Students enrolled in the Energy Minor may choose from three curricular tracks: Fossil Energy, Renewable Energy, and General. All students must take an Introduction to Energy course, Energy Economics and Global Energy Policy in addition to courses specifically designed for each track. Additionally, an opportunity exists for students who do not wish to enroll in the Energy Minor to earn special recognition in an Area of Special Interest (ASI). The ASI recognition requires a minimum of 12 credit hours of acceptable course work and 2 additional courses selected from the Energy-related course list.

To meet present and future domestic and global energy requirements, we, as educators, are charged with educating our engineering graduates in the areas of renewable, nuclear and unconventional (energy) fossil-based resources in addition to conventional coal, oil and gas energy sources. The Energy Minor at CSM is a novel educational approach that accomplishes this goal.
Design Tools and Workflows to Mitigate Drilling Vibrations
Authors: Bailey J. R. , Wang L. , Tenny M. J. , Armstrong N. , Zook J. R. , Elks W. C.
Published: February 2011

Design tools and workflows to mitigate drilling vibrations have been developed, demonstrated, and documented for several field drilling applications. This paper provides two new case studies to illustrate how this vibration mitigation methodology may be applied. Dynamic motions of the bottomhole assembly are known to be highly detrimental to the drilling process, resulting in unplanned trips, reduced rate of penetration, shortened bit and tool life, and MWD failures. The utility of the BHA design tool and the associated workflow will be illustrated in the context of how the methods have worked in conjunction with improved operating practices to achieve better drilling performance.

One case study shows how vibrations modeling can be used while drilling is underway to select a better BHA design, when it has been recognized that vibrations are a key performance limiter. Another case study illustrates how the vibrations modeling may be used to choose a preferred BHA design in advance of drilling a well or hole section. This proactive predrill workflow provides for advance planning and alignment with service providers. Both of these case studies illustrate how the method can be used to hindcast field results to understand performance change from one BHA to the next.

Vibrations mitigation through BHA design modification, operating parameter selection, and follow-up surveillance is proving to be highly cost-effective in the operator's "relentless re-engineering" process to reduce drilling costs. These technology applications are now being applied on a global scale.
Efficient Hierarchical Processing and Interpretation of Triaxial Induction Data in Formations with Changing Dip
Authors: Wu Peter , Wang Gong Li , Barber Tom
Published: February 2011

Triaxial induction tools have contributed considerably to the understanding of thinly bedded reservoirs, in which the use of both horizontal and vertical resistivity (Rh and Rv, respectively) reduces the uncertainty in laminated sand petrophysical analysis of hydrocarbon in place. At the same time, existing answer products, based on a windowed 1D inversion, return dip and azimuth of the formation as well as Rh and Rv. The dip and azimuth, however, are constrained to be constants over the length of the inversion window, usually at least 10 ft, and often much longer. For many formations in complex environments, the necessary assumptions for using a 1D inversion are at odds with the actuality of the formation, and the results are of questionable quality.

An inversion based on a homogeneous anisotropic formation model was introduced as part of the oil-based mud (OBM) borehole correction for the multiarray triaxial induction tool. It has been observed that this simple model can give better results in some 3D formations than those from the 1D inversion. The authors have taken this observation and have developed a new zero-D inversion that is divorced from the borehole correction algorithm so it can work in all environments, both OBM and water-based mud (WBM). This new process has been implemented in a hierarchical manner with a second-generation 1D inversion algorithm to produce a workflow that allows the best estimates for dip, azimuth, Rh, and Rv in complex reservoirs with changing dip. The results from the zero-D inversion are used to identify the complexity of the formations. The 1D inversion is run or displayed only through those zones in which the 1D model is valid, namely beds with relatively constant dip and azimuth. This new workflow combines the results from both the zero-D and 1D algorithms to produce the best results. Tests with model data of fully 3D formations show that this hierarchical processing workflow returns better results than those from the 1D inversion alone without the guidance of the zero-D inversion.

The results in several complex reservoirs illustrate the applicability of the new algorithms and workflow. Backed by the new process, we expect the triaxial induction measurements to become routinely used in a wide variety of formations.
First Rotary Steerable System Drilling With Dry Air is Used to Further Improve Low Cost Development of an Unconventional Gas Reservoir
Authors: Wilhide Scott , Doebereiner Dan , Smith Jeremy , Raymond Brad , Weisbeck Denis , Ziemke Brian
Published: February 2011

This paper presents the first use of a Rotary Steerable System (RSS) using air as the drilling fluid. The case history is in an ongoing unconventional gas development in the Appalachian Basin of the northeast United States. The RSS has been integral to increasing lateral lengths and corresponding increases in production while reducing development costs. Since 2006, EQT Production has developed Devonian reservoirs in Kentucky, Virginia and West Virginia using underbalanced, horizontal drilling techniques. The low (200-500 psi) bottom hole reservoir pressure does not allow drilling with fluid. Typical horizontal wells have had 3,000 ft laterals drilled with air, positive displacement motors, and electromagnetic telemetry (EM) MWD systems; that remains the predominate drilling technique. The air compatible RSS was employed to increase lateral length and production.

Well 568478, in Letcher County, Kentucky became the first well to have a horizontal section drilled underbalanced using RSS with dry air. To date, eight wells have been drilled with lateral lengths from 3,800 -6,000 ft. Preliminary results show that the reserves developed are proportional to the lateral length drilled. The rates of penetration (ROP) with the RSS in the additional footage were similar to or greater than those in shorter laterals drilled with a motor.

The RSS, with an integral EM MWD, has proven to be a technically feasible option in air drilling environments. The comparable ROP and resulting lower lateral costs per foot achieved with the RSS allows drilling horizontal wells with air beyond their previous limits, enabling greater production footage from fewer wellbores. It further allows drilling portions of the reservoir previously unreachable due to surface constraints such as topography.

Many of the learnings to implement the RSS technology also applied to the use of the positive displacement motors (PDMs) previously used. These learnings were applied to the motors and significant improvements were made in drilling horizontals with these tools. Motor capability was pushed beyond limits previously established in the areas being drilled.

As a result of the success with RSS and PDMs on extended laterals, EQT Production is extending the lateral length from 3,000 ft to 5,500 -7,000 ft on a plurality of the future wells drilled in the Devonian section.
Evaluation of Time to Flow Stabilization and Effective Drainage Area of Slow-Stabilizing Wells Using Production Decline Analyses
Authors: Poe B. D. , Poston S. W.
Published: February 2011

Estimation of the reservoir drainage area, hydrocarbons-initially-in-place, and the production time required for the onset of reservoir boundary effects to be exhibited in the production performance of low permeability reservoirs is of great interest and concern for reservoir and production engineers, reserves analysts, financial institutions, and investors. More generally, it has been observed historically that extrapolation of the results of decline curve analyses of the early transient production performance of oil or gas wells in slow-stabilizing reservoirs can result in tremendous estimation errors of these important reservoir parameters.

Reservoirs that can require a long production time to achieve stabilized boundary-dominated flow may be low permeability, heterogeneous, layered, or naturally fractured. Examples of well completion types that can also result in long production times before flow stabilization are hydraulically fractured or horizontal wells. This paper presents a decline curve analysis technique that can be used to improve the estimation of the reservoir effective drainage area, initial-fluids-in-place, and production time for the onset of boundary effects to be observed in slow stabilizing oil or gas wells.
Model to Predict CO2 Leakage Rates Along a Wellbore
Authors: Tao Qing , Checkai Dean , Huerta Nicolas , Bryant Steven L.
Published: February 2011

Large-scale geological storage of CO2 is likely to bring CO2 plumes into contact with a large number of existing wellbores. The flux of CO2 along a leaking wellbore requires a model of fluid properties and of transport along the leakage pathway. The leakage pathway in wells that exhibit sustained casing pressure (SCP) is analogous to the rate-limiting part of the pathway in existing wellbores along which CO2 may leak. Thus field observations of SCP can be used to estimate transport properties of a CO2 leakage pathway. We develop a more robust optimization algorithm to get the best data fit in the SCP model. Constraints from well construction geometry and from physical considerations reduce the range of estimated permeability. We then describe a simple CO2 leakage model. The model accounts for variation in CO2 properties along the leakage path and allows the path to terminate in an unconfined (constant pressure) exit. The latter assumption provides a worst-case leakage flux.

Using pathway permeabilities consistent with observations in SCP wells, we obtain a range of CO2 fluxes for various boundary conditions. In leakage pathways corresponding to the slow but nonnegligible buildup of casing pressure, the CO2 fluxes are comparable to naturally occurring background fluxes observed at ground surface. In pathways corresponding to rapid buildup of casing pressure, the fluxes are comparable to measurements at Crystal Geyser (Utah), a natural CO2 seep. Uncertainty in pathway permeability has a first-order effect on uncertainty of CO2 flux. Uncertainty in the length of the pathway has a comparatively minor effect. Increasing the CO2 at the base of the pathway does not dramatically increase the CO2 flux above the purely buoyancy-driven value.
Wellbore Dynamics of Carbon-Sequestration Injection - Well Operation
Authors: Mireault R.. , Stocker R.. , Dunn D.. , Pooladi-Darvish M..
Published: February 2011

This paper uses the experience gained over the past 13 years in analyzing and modeling wells that inject mixtures of hydrogen sulphide and carbon dioxide from sour gas plants to model the operating performance of injection wells for long term CO2 sequestration from electrical power plants. To predict wellhead pressures, a numerical simulation model integrates a modified Peng-Robinson equation-of-state for fluid phase behavior with a wellbore model and a multi-step adaptation of the Cullender and Smith method to account for the friction and hydrostatic pressure changes associated with flow in the wellbore.

As the world embarks on large scale capture and injection of CO2 emissions from electrical power plants, understanding the operating characteristics of the injection well(s) will be critical to the design, construction and operation of these systems. Unlike water injection wells, increasing the injection rate for a CO2 well does not necessarily increase its wellhead operating pressure. A methodology to estimate wellhead operating pressures is a key requirement for the proper design of the injection wells and the CO2 surface facilities. It may also help engineering and operations personnel, as well as regulatory agencies to understand the complex behavior of CO2 injection wells.

Pressure gradients in aquifers or reservoirs suitable for CO2 sequestration may range from a normal hydrostatic gradient to extremely sub-normal in depleted hydrocarbon reservoirs. Two injection cases present wellbore pressure profiles for injection into a depleted and a normally pressured reservoir at rates of 20, 100 and 280 103m3/d. Three sensitivity studies illustrate the impact of bottomhole sandface pressure, CO2 stream composition and wellhead temperature on wellhead pressure. Depending on conditions, the CO2 stream may undergo phase transitions from a gas or liquid at the wellhead to dense phase fluid in the wellbore and back to gaseous or supercritical out in the reservoir. The complex interactions between phase behavior, fluid density and pressure can lead to unexpected operating characteristics, including an increase in injection rate or sandface pressure with little or no change in wellhead injection pressure.
Modeling CHOPS Using a Coupled Flow-Geomechanics Simulator With Nonequilibrium Foamy-Oil Reactions: A Multiwell History Matching Study
Authors: Rivero Jose A. , Coskuner Gokhan , Asghari Koorosh , Law David H. , Pearce Andrew , Newman Robert , Birchwood Richard , Zhao John , Ingham Jon
Published: February 2011

Cold Heavy Oil Production with Sand (CHOPS) has been widely and successfully applied for the last three decades in the Heavy Oil Belt region that straddles the provinces of Alberta and Saskatchewan in Canada. As its name suggests, the method relies on continuous production of sand to improve the recovery of oil from the reservoir. In CHOPS, a significant pressure drawdown around the wellbore is created by using progressive cavity pumps, which causes the loosely consolidated formation to fail, creating increased permeability channels, usually called wormholes, through which, a slurry-like mixture of sand, oil and water flows.

Many attempts have been made to use conventional numerical reservoir simulators to model the CHOPS process. However, many of the commercial finite-difference reservoir simulators do not incorporate capabilities to model the complex geomechanical processes responsible for the failure of poorly consolidated formations in CHOPS. To circumvent these limitations, several approaches have been proposed. The most common relies on explicitly defining high permeability channels that radiate from the producing wells in an attempt to mimic wormholes created during CHOPS production.

In this paper, we present a different, more rigorous approach that relies on the coupling of a finite-element geomechanical simulator with a finite-difference reservoir simulator. In the coupling process, the geomechanical simulator uses the pressure gradients calculated by the reservoir simulator to determine changes in the stress regime of the reservoir. In the case of CHOPS, these changes cause failure in the loosely consolidated formation, which in turn induces sand production with a corresponding increase in porosity and permeability. The new porosity and permeability values in the affected gridblocks are then fed back to the reservoir simulator, which is now capable of incorporating the effects of formation failure into fluid flow calculations. This process is then repeated at user-controlled intervals during the course of the simulation. The methodology has been validated by successfully history matching the production data from a section of a heavy oil field operated by Husky Energy in Western Canada. In this paper we compile the data integration efforts to create a coupled geomechanical model and the results of the history match.