bluuebunny/crossref_metadata_2025 huggingface dataset:
Analysis of Exploration Expenditure for Unconventional Gas: How Investing in Exploration Would Improve Reserves and Production
Authors: Virine L.
Published: February 2011

In recent years petroleum producers have become engaged in significant expenditure towards exploration and development in conventional and unconventional gas plays in United States and in Canada. How efficient would be such expenditure for different producers and different basins?

This paper describes the methodology of the analysis of correlation between exploration expenditure and producer's reserves and production. A model has been developed to quantitatively assess exploration expenditure, production, and reserves of various producers for different conventional and unconventional gas plays. The model incorporates producer's booked reserves and production from the public sources as well as reserves and production forecasts. The model is used to analyze different types of exploration expenditure, including land, drilling and seismic, incurred at different time periods prior to the booking of reserves and production. The proposed methodology has been used to compare the exploration expenditure of various producers operating in the United States. The analysis has demonstrated an overall positive correlation between exploration expenditure and reserves and production; however the correlation showed significant variance between various producers operating in different plays. The proposed methodology and the result of the study can be applied to the analysis of efficiency of the exploration investment, which in turn can help improve corporate planning process.
Design Considerations to Test Sealing Capacity of Saline Aquifers
Authors: Zeidouni M. , Pooladi-Darvish M.
Published: February 2011

The geological storage of carbon dioxide (CO2) provides the possibility of maintaining access to fossil energy, while reducing emissions of CO2 to the atmosphere. One of the essential concerns in geologic storage is the risk of CO2 leakage from the storage formations. The leakage occurs through possible pathways in the seal. Characterization of the CO2 leakage pathways from the storage formations into overlying formations is required. The aquifer cap-rock may be characterized before CO2 storage. This will allow for the determination of proper storage aquifers and locations for the injection wells. In a companion paper, a flow and pressure test has been suggested for characterization of leakage pathways in aquifer cap-rock. Water is injected in the target aquifer, and the pressure is observed in an overlying aquifer. The pressure data are analyzed to characterize the leakage pathways in the cap-rock. In this work, design considerations to maximize the capability of leakage characterization are presented.

A leakage pathway can be characterized by the leak transmissibility and location parameters. A successful test should be able to provide sufficient information to evaluate the leakage parameters. In this work, different strategies are evaluated in order to achieve a successful test. The strategies include increasing the sampling frequency, use of pulsing, increasing the number of monitoring/injection wells and utilization of prior information. Prior information on the leak is provided through analysis of the pressure derivative curve.

Estimation of the leakage parameters is actually an inverse problem that is generally ill-conditioned and very sensitive to noise. The information provided by different strategies is evaluated, based on their effects on well-posing the inverse problem. The effects are studied based on information and correlation matrices, as well as the confidence interval.
Effect of Oil Viscosity, Permeability and Injection Rate on Performance of Waterflooding, CO2 Flooding and WAG Process in Recovery of Heavy Oils
Authors: Torabi F. , Jamaloei B. Y. , Zarivnyy O. , Paquin B. A. , Rumpel N. J. , Wilton R. R.
Published: February 2011

The economic life of a typical heavy oil reservoir under primary or secondary recovery schemes can be short lived or near their limit, with recovery factors in the range of 5–15%. Waterflooding alone has been successfully practiced in the Lloydminster area of the Western Canada for decades. Heavy oils located in thick reservoirs have benefited from the application of thermal, gravity drainage processes; however, thin, unconsolidated heavy oil reservoirs are unsuitable due to lack of drainage height. These reservoirs may benefit from immiscible CO2 or CO2-WAG processes.

This paper examines the effect of oil viscosity, permeability and injection rate on the performance of heavy oil waterflooding, immiscible CO2 flooding and immiscible CO2 water-alternating-gas (WAG) processes. A series of 11 sand packfloods were conducted using 440 and 1,500 mPa·s heavy oils and sand packs with absolute permeabilities of 12 and 40 μm2. Water injection volumes for the waterfloods were 1.5 pore volumes (PVs) at rates of 0.112, 1.124, and 5.62 cc/min. For the CO2 flooding process, 4.5 PVs of gas were injected at a rate of 1 cc/min. For the WAG process, the water:CO2 slug ratios were varied from 1:1, 1:2 and 2:1. A 99.9% purity CO2 gas stream was used for all gas floods. All experiments were performed at a controlled temperature of 25°C and 345 kPa.

Among the 11 sand packfloods conducted, the waterfloods consistently yielded the highest recovery factor for both heavy oils and sand packs, with 48-52% OOIP recovered and most of this recovery occurring during 0.112 cc/min. During CO2 flooding of the 440 mPa·s oil, 48.5% OOIP was produced from the 40 μm2 sand pack. From the same fluid-sand system, a 1:1 slug ratio, CO2-WAG process produced 42% OOIP. For the 1,500 mPa·s heavy oil, 1:2 and 2:1 slug ratios of CO2-WAG both produced ~25% OOIP from the 40 μm2 sand pack and a 1:1 slug ratio produced 35% OOIP from the 12 μm2 sand pack. All WAG injection schemes were compared on a 2.5 PV injected basis. These results suggest that the role of displaced fluid viscosity plays the most prominent role in the recovery of heavy oil.
Ultra-Lightweight Proppants in Shale Gas Fracturing
Authors: Gaurav A. , Dao E.K. , Mohanty K.K.
Published: February 2011

The goal of the present work is to evaluate ultra light weight proppants for fracturing of shale gas reservoirs. Three ultra light weight proppants (ULW-1, ULW-2, and ULW-3) have been studied. The mechanical properties of the proppant packs as well as single proppants have been measured. Conductivity of proppant packs has been determined as a function of proppant concentration, confining stress, and temperature. The crush strengths of all the three proppant packs are higher than typical stresses encountered in the Barnett shale. ULW-1 and ULW-2 are highly deformable and do not produce many fines. ULW-3 has a higher Young's modulus and produces fines. The proppant conductivity decreases with increasing confining stress, but it is not a strong function of the proppant concentration for bothe ULW-1 and ULW-2. A partial monolayer of ULW-2 (0.07 lbm/ft2) provides slightly less or as much conductivity as a thick proppant pack with a concentration of 0.7 lbm/ft2. At 6000 psi stress, the conductivity of ULW-1 seems to decrease a little as the proppant concentration increases and then increases. Application of light weight proppants in stimulation treatments in shale reservoirs can lead to long propped fractures, which can improve the productivity of fractured shale reservoirs.
Evaluating the Production Potential of Hydraulically Fractured Horizontal Completions Using Engineering and Data-Driven Modeling Techniques
Authors: Shelley R.F. , Dzubin B. , Shah K.
Published: February 2011

Drilling horizontally and hydraulic fracturing is becoming the well type of choice in ultra-low permeability sands and shale. However, as the complexity of these wells increases, the challenge of evaluating the effectiveness of these completions proves more problematic. The reason: There are challenges related to the uncertainties around hydraulic fracturing, wellbore placement/orientation, formation evaluation, and fracture mapping a 1-to-2-mile-long horizontal wellbore. Other difficult-to-model issues such as frac spacing, convergence, compartmentalization methodology, perforation methodology, zone isolation, drillout/cleanup, and other operational procedures have a significant effect on the production result and gas recovery. This paper describes a methodology consisting of both engineering and data-driven modeling techniques, which are intended to quantify these effects and the effects of other decisions made related to the construction and completion of hydraulically fractured horizontal wells. A discussion about the merits and drawbacks of the two approaches and why performance of both produces new understanding about completion and frac effectiveness follows. Several Bakken case histories are presented to demonstrate usefulness and document value.
Microseismic Mapping of Laboratory-Induced Hydraulic Fractures in Anisotropic Reservoirs
Authors: Chitrala Y. , Moreno C. , Sondergeld C. H. , Rai C. S.
Published: February 2011

Microseismic monitoring of hydraulic fractures typically produce spatial and temporal plots of hypocenters without any estimates of uncertainty leading the engineer to believe the hypocenter locations are absolute. The hypocenter location problem becomes more complex in anisotropic shale reservoirs. Hypocenter locations are determined from the arrival times of P-wave and/ S-waves and a known velocity model. The difference in the velocity structure and the complex fracture network make accurate fracture mapping difficult. The fracture properties are a function of the magnitudes and directions of applied stresses. We report on a series of laboratory nanoseismic studies during controlled hydraulic fracturing of limestone, sandstone and a strongly foliated metamorphic rock, pyrophyllite. In addition to hypocenter locations, we report on focal mechanisms, frequency analysis, source dimensions and spectral characteristics of the emitted event. Hydraulic fracturing is dominated by shear failure; fracture alignment is controlled as predicted by applied stresses in isotropic materials. However, hydraulic fracture propagation in anisotropic materials is altered by the magnitude of anisotropy but is predictable when the anisotropic elastic constants are known.
A Green Alternative for Determination of Frac Height and Proppant Distribution
Authors: Mulkern Mark , Masnyk Bob , Kramer Hermann , Sites Joseph
Published: February 2011

As regulations and public awareness regarding hydraulic fracture operations continue to change, it is important to continue to look for options to reduce risk to both the environment and personnel. Current fracture diagnostic technology uses radioactive materials which can pose a high risk from a health, safety and environment (HSE) perspective. Exposures to people and the environment to radioactive chemicals; and the potential to cause pollution or long term detrimental health problems, are great. A technology has been developed to allow fracture diagnostics to be performed with zero-risk to the environment and personnel.

The technology involves using Boron Carbide particles added to the frac slurry as a tag material. Boron Carbide is a ceramic compound that has a 75% abundance of Boron by weight and the same density as Silica. It is a compound that is chemically inert under typical conditions of hydraulic fracturing.

Because Boron is a neutron absorber, post-frac detection is accomplished by using a neutron device utilizing an Am-241Be sealed source which detects descending neutron and gamma count rates, as well as, capture gamma validation by energy discrimination across tagged intervals. This method will give both near and not near well bore dimension and provides Neutron-Neutron (N-N) and Neutron-Gamma (N-G) differences against initial base line reference data.

Field data and analysis of results are presented for a vertical coalbed methane well in Virginia as well as a horizontal Berea Sanstone well in Kentucky.
Flow Rate Behavior and Imbibition in Shale
Authors: Wang Dongmei , Butler Raymond , Liu Hong , Ahmed Salowah
Published: February 2011

Shale is an important source of oil and gas in North America. Most shale reservoirs have a low porosity and ultra low permeability with naturally fractures. Shale formations have long been considered important source rocks, capable of producing oil at economic rates when completed by hydraulically fractured horizontal wells. As part of our investigations of a new chemical imbibition idea (using surfactant or brine formulations) to stimulate oil recovery from shale, accurate determination of shale permeability and porosity is needed to assess potential recovery rates. Our interest in this study is in oil flow through shale, especially relevant to the Bakken formation oil.

Our first studies in this area focused on an outcrop shale, specifically the Odanah member of Pierre Shale in North Dakota. As part of an effort to assess the potential for imbibition to recovery oil from shale, we studied porosity, permeability to oil, permeability to water, and imbibition for the Pierre shale. We found that porosities for Pierre shale cores were relatively high—from 25% to 35%. Bakken oil imbibed into dry Pierre shale cores (up to 5-mm in thickness) to the same extent as could be achieved by forced injection of oil (i.e., achieving the same oil saturations for both processes). Permeability to a clean mineral oil (Soltrol 130) was higher than for Bakken oil—apparently because of deposition of wax/asphaltenes/particulates on the core faces when injecting Bakken oil. Permeability to oil for Pierre shale cores (with no water present) ranged from 3x10-5 to 5x10-4 md when injecting Bakken oil and from 2x10-4 to 1.3x10-3 md when injecting Soltrol 130. For both oils in cores with thicknesses ranging from 0.65 to 5 mm, permeabilities were basically independent of flow rate, in agreement with expectations from the Darcy equation. A saline brine imbibed effectively into oil-saturated Pierre cores, yielding recovery values up to 41% OOIP. During exposure to brine, our results indicated an increase in permeability—presumably by mineral dissolution during forced brine injection and by cracking (possibly due to clay swelling) during spontaneous imbibition. This result is encouraging for the application of imbibition to enhance oil recovery from shale. Prior to these studies, we feared that exposure to brine might reduce shale permeability because of clay swelling.

The laboratory results will help during a current study of surfactant and brine imbibition in Bakken shale.
Effective Implementation of High Performance Water Based Fluid Provides Superior Shale Stability Offshore Abu Dhabi
Authors: Mehtar Mohammed , Brangetto Martial , Soliman Ahmed Abou , Mielke Scott , Alfonzo Nelson , Young Steve
Published: February 2011

Drilling offshore Abu Dhabi presents some unique challenges primarily related to wellbore instability in directionally drilled wells through the unstable Nahr Umr and Laffan shale formations. This not only affected drilling performance and cost millions of dollars due to non-productive time (NPT), but had also placed constraints on the Company’s field development plans, as it was not possible to drill high deviation wells through these shales with a high degree of success. It was a major challenge to develop and engineer a water-based drilling fluid that could effectively eliminate shale instability encountered while drilling these high deviation wells.

The stabilization of these highly laminated shales required an effective synergistic blend of products to both maintain the chemical stability of the shales and minimize the transmission of fluid pressure into the shales, while sealing both natural and induced micro-fractures. The development of the ideal types and blend of products, treatments and engineering techniques tailored to these specific rock requirements is crucial to drilling success. The net result of the correct application of this unique drilling fluid system has been to mitigate the incidences of cuttings accretion, wellbore instability, time-related failure and induced losses into permeable formations, thereby eliminating drilling non-productive time.

This paper describes the development and field application of a uniquely engineered water-based drilling fluid that demonstrates enhanced shale stabilization properties, much like the invert emulsion systems, but without the associated waste management equipment and logistics and environmental exposure. Additionally, the development and use of a new class of sealing additives is outlined showing how improved stabilization of the wellbore can be achieved while drilling these older, highly laminated shale formations. Extensive laboratory work was carried out under simulated conditions, on both the fluid system and sealing additives to optimize the fluid formulation. Thereafter, successful field applications were carried out in high inclination wells in the area. Drilling performances were greatly enhanced compared to conventional fluid systems, which accrued significant cost savings to the operator. Further, there is additional flexibility to drill high deviation wells through these shales, as required to reach a reservoir target. This development approach and the use of the unique stabilization additives can be utilized in many other areas where issues of wellbore instability in older and laminated or fractured shales exist.
Surface Microseismic Mapping Reveals Details of the Marcellus Shale
Authors: Hulsey B. J. , Cornette Brian , Pratt David
Published: February 2011

The mapping of microseismic events induced by hydraulic fracturing plays an important role in well completion and design. This is especially true in a newly developing area of gas producing shales. In this case study, we will show how the microseismic monitoring of a hydraulic fracture treatment in the Marcellus Shale identified a pre-existing natural fault which intersected the wellbore. The data from nearby wells indicated several possibilities of structural evolution affecting the producing formation. These range from regional reverse or strike-slip faulting to small displacement local reverse faulting. The hydraulic fracture stimulation was monitored using a 10 line, radial surface array composed of 1000 vertical component geophone stations. The treatment consisted of seven perforated stages stimulated with slickwater and proppant.

Microseismic activity mapped during the early stages of the treatment is consistent with the regional stress direction and indicates that stages 1-4 activated natural fractures oriented along the maximum horizontal stress direction. During stages 5 and 6, the hydraulic fracture encountered a pre-existing natural fault. A source mechanism was determined for events occurring along the fault, identifying oblique failure with strike-slip and reverse faulting along the steeply dipping fault with SSE strike. This indicates that the regional strike-slip fault, with a strike similar to the break we observed at other offset wells, is most likely responsible for the geological evolution of this formation.
Fracture Extent and Zonal Communication Evaluation Using Chemical Gas Tracers
Authors: Mulkern Mark , Asadi Mahmoud , McCallum Scott
Published: February 2011

Chemical gas tracers have been used in gas flood projects to evaluate interwell communications, formation heterogeneity, channeling, and to calculate volumetric sweep efficiency. For the first time, these tracers are used to evaluate the extent of fracture communication with offset wells and also to evaluate zonal communication between four hydraulically fractured reservoirs. The four horizontal wells are drilled and completed in Berea, Chagrin, Lower Huron Siltstone, and Lower Huron reservoirs. Each well was individually fractured with nitrogen gas in nine stages. A different chemical gas tracer was injected in each of the horizontal wells during the fracture stages with the carrier gas. Upon the completion of each fracture treatment, the well was shut-in to frac the next well. Upon the completion of the last fracture treatment, the well was shut-in for the reservoir pressure to stabilize before all four wells were put back on production. Flowback gas samples were collected at the wellhead for tracer detection analysis and hence flowback analysis. In addition, produced gas samples were collected at the offset wells for gas tracer detection to evaluate the extent of the fractures, interwell communication and formation heterogeneity. The results of flowback, zonal communication and extent of fracturing are presented in detail.
A Practical Approach for Production Data Analysis of Multilayer Commingled Tight Gas Wells
Authors: Ali T. , Cheng Y. , McVay D. A. , Lee W. J.
Published: February 2011

This paper proposes and validates a robust methodology to estimate fracture properties (half-length and conductivity), formation permeability, and, where possible, drainage area of individual layers in hydraulically fractured vertical gas wells producing commingled from multiple layers. Estimation of these fracture and individual layer properties is required to evaluate fracture treatment effectiveness and forecast future production for these wells.

To achieve our objectives, we applied an analytical elliptical flow solution to analyze production data from hydraulically fractured vertical tight gas wells producing from multilayer reservoirs. We were able to estimate the fracture half-length, formation permeability, and minimum drainage area of each layer. This study considered variations in completion details, initial reservoir pressures, reservoir temperatures, and other reservoir parameters in layers producing simultaneously.

The technology we developed includes the following components used in our analysis: flow rate allocation using available production logging test data, deconvolution to convert variable-rate pressure data into constant-rate pressure responses, identification of the elliptical flow regime, and analysis of elliptical flow data. We developed and present a new technique to identify the elliptical flow regime. We validated our method with synthetic data generated with a reservoir simulator.
Facilities Design for Transport of Fluids with GRE Line Pipes – ISO 14692-3 Application –
Authors: Stupenengo Franco A.
Published: February 2011

GRE pipes have a distinct advantage in the transport of fluids, both liquids and gases, comparing with carbon steel pipes. This is mainly due to the lower surface roughness inside the pipes and higher corrosion resistance for most service conditions to which they may undergo in the oil and gas industry.

The systems design for the transport of fluids through GRE pipe is performed simultaneously responding to the three following basic requirements: a) hydraulic design, b) structural design; and, c) study of system vulnerabilities.

In this paper it has been introduced and explained the procedure described by ISO 14692-3, it has been also introduced a pipeline Case Study, for which it had been get two alternative products that fulfill the Case Study Hydraulic Design requirements and are submitted to the Structural Design. It is demonstrated that once analyzed them by the Structural Design, it has been detected the need to redefine the pre-selected products choosing a higher pressure rating.
Depositional Environments Being Investigated by the National Energy Technology Laboratory NETL for Potential Geologic Storage of CO2
Authors: Dressel Brian , Olsen David , Brown Bruce , Plasynski Sean , Litynksi John
Published: February 2011

A need exists for further research on carbon sequestration technologies to capture and store carbon dioxide (CO2) from stationary sources that would otherwise be emitted to the atmosphere. Carbon Capture and Storage (CCS) technologies have the potential to be a key technology for reducing CO2 emissions and mitigating global climate change.

Deploying these technologies on a commercial-scale will require geologic storage formations capable of (1) sequestering large volumes of CO2, (2) receiving CO2 at an efficient and economic rate of injection, and (3) retaining CO2 safely over extended periods. Eleven major types of depositional environments, each having their own unique opportunities and challenges, are being considered by the U.S. Department of Energy (DOE) for CO2 storage. These different classes of reservoirs include deltaic, coal/shale, fluvial, alluvial, strandplain, turbidite, eolian, lacustrine, clastic shelf, carbonate shallow shelf, and reef. Basaltic interflow zones are also being considered as potential reservoirs.

DOE has recently completed a study which investigates the geology, geologic reservoir properties and confining units, and geologic depositional systems of potential reservoirs and how enhanced oil recovery and coal bed methane are currently utilizing CO2. It looks at the classes of geologic formations that have been identified as having the potential to be CO2 reservoirs, their distribution and potential storage volumes.

This study also discusses the efforts that DOE is supporting to characterize and test small and large scale injections of CO2 into these different classes of reservoirs. These tests are important to better understand the directional tendencies imposed by the depositional environment that may influence how fluids flow within these systems today, and how CO2 in geologic sequestration is anticipated to flow in the future. Although diagenesis has modified fluid flow paths during the intervening millions of years since they were deposited, the basic architectural framework created during deposition remains. Geologic processes that are working today also existed when the sediments were initially deposited. Analysis of modern day depositional analogs, evaluation of core samples, outcrops and well logs from ancient subsurface formations give an indication of how formations were deposited and how fluid flow within these formations is anticipated to flow.
Imaging Texture and Porosity in Mudstones and Shales: Comparison of Secondary and Ion-Milled Backscatter SEM Methods
Authors: Milner M. , McLin R. , Petriello J.
Published: February 2011

Observations from a number of unconventional reservoirs lead us to conclude that four major pore types exist in fine-grained reservoir and non-reservoir rocks, that they are effectively connected, and that pore sizes from nanometers to microns must be considered when evaluating size distributions. This paper uses SEM imaging of Haynesville, Horn River, Barnett and Marcellus Shales to illustrate that pore types other than those hosted by organics are present in unconventional shale gas reservoirs, and that they are continuous and connected to kerogen-hosted pores. In addition, we present evidence that the maximum size of pores originating in organic matter is determined by the size of the kerogen mass (in the case of organic particles) or the geometry of enclosing crystals (in the case of amorphous, pore-filling kerogen). Pairs of secondary and ion-milled backscatter SEM images address the misconception that large pores observed in secondary electron images are grain pullouts.

2-D image analysis and 3-D volumetric reconstructions to study pore distributions should take rock microtexture and the various pore types into consideration. A combined method using thin section textural analysis, XRD, and SEM imaging is recommended to address scaling issues when choosing samples for 2-D and 3-D volumetric analysis.
Effluent Metering and Liquid Gas Ratio Analysis
Authors: Conrad L. M. , Howell K.
Published: February 2011

Beginning in 2007, the Industry Measurement Group (IMG) undertook a two year initiative focused on creating technically based regulations that would allow for improved economics on low pressure, low liquid gas plays in Western Canada. The initiative was supported by the Canadian Association of Petroleum Producers (CAPP) and led to a joint CAPP/IMG review of Effluent metering applications and the associated testing requirements for gas wells set forth by the regulatory authorities in British Columbia and Alberta.

The Canadian Association of Petroleum Producers (CAPP) is the voice of Canada's upstream oil, oil sands and natural gas industry. CAPP represents companies that explore for, develop and produce natural gas and crude oil throughout Canada. CAPP's member companies produce about 90 per cent of Canada's natural gas and crude oil.

The Industry Measurement Group (IMG) represents 100 members from upstream, transmission, provincial and federal organizations. IMG is recognized by CAPP as a formal voice for measurement related activities in the Western Canadian Oil and Gas Industry. The objectives of the IMG organization include the identification of common areas of concern relating to measurement and encouraging co-operation in establishing action plans, increasing awareness of measurement issues and fostering beneficial relationships. IMG also acts as a liaison between the industry and regulatory bodies in the development of industry accepted standards for measurement activities.

The examination of metering applications and testing requirements for gas wells in British Columbia and Alberta led to the conclusion by both industry and the regulator that there was merit in conducting a timely multi-jurisdictional review. The primary objectives of the joint CAPP/IMG review were two fold. Firstly, it brought all parties together to form a common framework for Effluent metering application and testing expectations, based on a risk and volumetric approach. Secondly, it supported an economical approach to the continued development of unconventional gas resource plays in Alberta and British Columbia, with a focus on well-site infrastructure and operational cost optimization.

This paper will provide the reader with insight into well testing requirements and the benefits of creating technically based, pragmatic regulations. The paper will also demonstrate how through the use of existing regulatory documentation, the CAPP/IMG project team was able to develop a new practical and pragmatic regulatory framework and policy for Effluent metering and well testing, which provides a common regulatory and industry approach across Alberta and British Columbia.
Automated Monitoring of a Hydraulic Fracture by Coalescence Microseismic Mapping
Authors: Woerpel J. Craig , Maxwell Shawn , Underhill Bill , Wolfe James
Published: February 2011

Coalescence microseismic mapping (CMM) is a method of hypocenter determination that does not require any human interaction during microseismic monitoring. Microseismic events can be detected, located and displayed on a laptop computer screen within seconds of their origin time. This paper describes both the method and results of a horizontal well case study in a tight gas reservoir.
A Simple Decline-Curve Analysis Approach for Evaluating Gas Reserves and Predicting Future Production in Gas Reservoirs
Authors: Bahadori A. , Vuthaluru H. B.
Published: February 2011

Decline curves are one of the most extensively used forms of data analysis employed in evaluating gas reserves and predicting future production. The parameters determined from the classical fit of historical data can be used to predict future production. The decline-curve analysis technique is based on the assumption that past production trends and their controlling factors will continue in the future and, therefore, can be extrapolated and described by a mathematical expression. In the present work, simple-to-use predictive tool, which is easier than existing approaches, less complicated with fewer calculations, is formulated to arrive at an appropriate estimation of nominal (initial) decline rate, and the Arps’ decline-curve exponent. The results can be used in follow-up calculations for analysis of past trends of decline in production performance i.e., rate versus time and rate versus cumulative production plots, for wells as well as reservoirs. The proposed simple-to-use approach can be of immense practical value for reservoir engineers and scientists to have a quick analysis on the production decline-curve of past trends of wells and reservoirs for wide range of conditions without the necessity of any field test measurements and/or trials. In particular, petroleum engineers would find the proposed approach to be user friendly involving transparent calculations with no complex expressions for their applications.
Systematic Team Approach Delivers Massive Performance Improvements in Shale Gas Play
Authors: Barton Steve , Lockley Russ , MacLeod Andrew M. , Pierce Garrett
Published: February 2011

The paper focuses on drill bit development for a specific natural shale gas play located within North America. These wells require advanced horizontal drilling techniques and extensive hydraulic fracturing to make them economically attractive. This paper details how a major operator has been able to make radical improvements in drilling performance in this area, leading to significant cost reductions.

A typical well consists of a vertical section, build section, and a final horizontal leg. When the operator started this project in 2008, the objective was to drill this entire main hole in just three bit runs; one for each directional leg described prior. In actuality, twelve to fourteen bits were utilized, averaging over forty days from drill-out to section TD. This made the economic viability of further development questionable.

A team approach enabled bit design modifications and improvements to be implemented in a controlled, continuous, and closely monitored program. A key component of this was the development of a unique flexible bit design developed specifically for directional applications in coordination with a leading supplier of motors. These bits contain novel features that allow rapid design modifications to be performed locally, significantly reducing response time, and allowing the program to proceed at a much faster pace than previously possible.

Within a matter of months, this systematic cooperative approach enabled the operator to achieve the initial objective of drilling the interval in 3 bit runs, but also their subsequent objective of drilling the interval in just two bit runs. Days to drill this section were drastically reduced from over forty to less than twelve days. The savings produced by this huge improvement in drilling performance has greatly assisted the economic viability of continued development in this basin.
Fast Track Reservoir Modeling of Shale Formations in the Appalachian Basin. Application to Lower Huron Shale in Eastern Kentucky.
Authors: Grujic O. , Mohaghegh S. D. , Bromhal G.
Published: February 2011

In this paper a fast track reservoir modeling and analysis of the Lower Huron Shale in Eastern Kentucky is presented. Unlike conventional reservoir simulation and modeling which is a bottom up approach (geo-cellular model to history matching) this new approach starts by attempting to build a reservoir realization from well production history (Top to Bottom), augmented by core, well-log, well-test and seismic data in order to increase accuracy. This approach requires creation of a large spatial-temporal database that is efficiently handled with state of the art Artificial Intelligence and Data Mining techniques (AI & DM), and therefore it represents an elegant integration of reservoir engineering techniques with Artificial Intelligence and Data Mining. Advantages of this new technique are a) ease of development, b) limited data requirement (as compared to reservoir simulation), and c) speed of analysis.

All of the 77 wells used in this study are completed in the Lower Huron Shale and are a part of the Big Sandy Gas field in Eastern Kentucky. Most of the wells have production profiles for more than twenty years. Porosity and thickness data was acquired from the available well logs, while permeability, natural fracture network properties, and fracture aperture data was acquired through a single well history matching process that uses the FRACGEN/NFFLOW simulator package.

This technology, known as Top-Down Intelligent Reservoir Modeling, starts with performing conventional reservoir engineering analysis on individual wells such as decline curve analysis and volumetric reserves estimation. Statistical techniques along with information generated from the reservoir engineering analysis contribute to an extensive spatio-temporal database of reservoir behavior. The database is used to develop a cohesive model of the field using fuzzy pattern recognition or similar techniques. The reservoir model is calibrated (history matched) with production history from the most recently drilled wells. The calibrated model is then further used for field development strategies to improve and enhance gas recovery.
Improving Marcellus Shale Performance Using PDC Bits with Optimized Torque Management Technology, Cutting Structure Aggressiveness and Unique Roller Cone Steel Tooth Cutting Structures
Authors: Brown Randy , Meckfessel Britney
Published: February 2011

The low formation unconfined compressive strength (UCS) and low abrasiveness in build and horizontal sections of a Marcellus shale well, relatively green PDC and roller cone dull bits, and the desire to drill fast at high build rates with one bottomhole assembly (BHA) facilitate the use of PDC bits with aggressive cutting structures and new torque management technology.

Aggressive PDC cutting structures that inherently drill at higher ROP generate high differential torque and erratic toolface leading to insufficient build rates.

If lower energy input to the PDC or less aggressive bits are employed to manage torque, instantaneous rate of penetration (ROP) can be lower.

Along with this, drillstring friction can result in less consistent and lower weight on bit (WOB), or high differential torque requiring lowered operating parameters and additional toolface resetting.

Due to these issues, instantaneous ROP and feet per day will be lower. This can also affect downhole tool loading and reliability and also toolface control, which can reduce build-up rate (BUR) capacity.

In build sections where PDC bits do not demonstrate planned build rates, roller cone bits are run to achieve the planned well path. The roller cone bit is used to manage torque and a unique tooth design is used to increase ROP over traditional bits.

This paper investigates the implementation and optimization of new torque management technology combined with the use of managed cutting structure aggressiveness of PDC bits and a unique roller cone bit cutting structure to determine the effects on operating parameters, toolface control, build rates, well path trajectory, cutting structure efficiency, feet drilled per day, instantaneous ROP and time savings.

Employing the new torque management technology on optimized, aggressive PDC cutting structures can result in faster drilled sections due to higher instantaneous ROP and less time spent in non-productive steering operations.
Production Analysis and Well Performance Forecasting of Tight Gas and Shale Gas Wells
Authors: Ilk D. , Currie S. M. , Blasingame T. A.
Published: February 2011

Estimation of reserves in tight gas and shale gas reservoirs is problematic due to the low to ultra-low permeability characteristics of these reservoir systems. The sole application of conventional decline curve analysis methodologies often yields erroneous reserve estimates. Therefore, the use of theoretically-based production analysis techniques has become a must to analyze well performance and estimate reserves.

The primary objective of this work is to develop a systematic workflow, which integrates model-based production analysis and rate-time relations, for the analysis/interpretation of well performance data in unconventional reservoirs. The major steps in the proposed workflow are:Diagnosis of production data.Construction of a base well/reservoir model utilizing static well/reservoir data as well as completion/stimulation parameters.Extrapolation of the model to predict well performance along with the use of rate-time decline relations.

The proposed methodology is demonstrated using data from unconventional reservoirs, including a horizontal well with multiple fractures. We present the application of rate-time relations to provide estimates of time-dependent reserves. The use of βq,cp-derivative is also illustrated in distinguishing data characteristics as well as identifying issues associated with data.
A New Approach to Drilling Hard Chert Contaminated Carbonate Formations in Kazakhstan
Authors: Donald Hugh H.
Published: February 2011

Exploration for, and production of, hydrocarbons in Kazakhstan frequently involves drilling extremely hard-carbonate sequences, which contain high concentrations of chert. Historically, in almost all cases, bit records show that these formations have been drilled with tungsten carbide insert (TCI) roller-cone style bits and occasionally polycrystalline diamond compact (PDC) bits. Both rotary and positive displacement motor (PDM) assemblies have been used.

Drilling extremely hard-carbonate lithologies has been accomplished with PDC and TCI bits, but with the presence of chert, this becomes a considerable challenge. Depending on the nature of the chert (e.g., disseminated or nodular) it may well be impossible for a PDC bit to drill with the PDC cutting structure failure mechanism being catastrophic breakage sustained by the high modulus of elasticity (i.e., brittle) PDC diamond tables.

The cutting structure failure mechanism for a tungsten carbide bit tends to be the degradation, through breakage and chipping, of the gauge row cutting structure. This in turn will induce severe wear of the heel rows and shirt tail areas, as they attempt to maintain gauge. Severe shirt tail wear and subsequent loss of shirt tail material will invariably result in premature seal exposure and seal/bearing failures.

Despite advances in PDC and roller-cone tungsten carbide insert designs, the drilling of extremely hard carbonates characterized by chert concentrations as high as 65% remains a considerable challenge with slow rates of penetration (ROP) and costly trips to change out bits.

This paper outlines the introduction of a new drilling system for this type of application in Kazakhstan, in the form of natural-diamond impregnated bits run in conjunction with high-speed turbines. A discussion of the drive systems and drill-bit evolution is presented. The definitive parameter for quantifying drilling efficiency is cost per meter (CPM), and several such examples of resounding CPM reduction are illustrated.
Upscaled Multi-Phase Flow Properties of Fracture Corridors
Authors: Ahmed Elfeel, M. , Couples G.. , Geiger S.. , Ma J..
Published: February 2011

Fractured reservoirs contain around 60% of the world’s remaining oil reserves. Fracture corridors have been noticed as a major architectural element in outcrops of fractured rock and are known to affect recovery by providing high-permeability flow conduits. Simulations of fractured reservoirs using multi-porosity and multi-permeability models has proven to be challenging, with ever-changing modifications being proposed since the introduction of the dual porosity model in the 1960s. To increase the reliability of reservoir simulation of fractured reservoirs, we propose a new workflow to represent fractured reservoirs by coupling Discrete Fracture and Matrix (DFM) models for fracture corridor properties (which uses finite element and finite volume methods), and the conventional single porosity simulation(which uses finite difference methods).

Relative permeabilities of fracture corridors are upscaled over a single grid block size using DFM models based on an unstructured mesh that accommodates fracture corridor patterns and characteristics. The upscaled relative permeabilities are transferred into a single porosity simulation model to reproduce the behaviour of fractured reservoirs without resorting to the transfer functions.

Various fracture patterns and apertures were studied to investigate their impact on flow properties. Also, different multiphase upscaling techniques were investigated based on the dominant driving forces and the type of boundary conditions used in the upscaling process.

A performance match was done between two models, a fine-mesh DFM model and a simple coarse single porosity model that uses the upscaled relative permeabilities. The models behaved similarly. Recommendations are derived as to how to use appropriate upscaling methods. The new workflow complements and may even have the potential to eliminate the need for classical dual-porosity models.
An Integrated Geomechanics Workflow for Caprock-Integrity Analysis of a Potential Carbon Storage
Authors: Khan S.. , Han H.. , Ansari S.. , Khosravi N..
Published: February 2011

Ensuring long-term containment of CO2 is critical for a safe geological storage of carbon. Although Carbon Capture and Storage (CCS) is feasible in depleted hydrocarbon fields, it can pose significant risk to safety and the environment if its containment is not ensured. An integrated geomechanics workflow to evaluate caprock integrity is presented in this paper. This approach integrates reservoir simulation which typically computes variation in formation pressure and temperature with geomechanical simulation which models variation in stresses. Coupling between these two simulation modules is done iteratively until an equilibrium state between formation pressure and stress is achieved within a given tolerance. The efficiency of this approach is demonstrated through a case study of a proposed carbon storage site in Canada where an injection rate of 600 tonne/day for 25 years is planned.
Use of Time-Lapse Seismic Data for Heterogeneity Characterization During CO2 Sequestration in Saline Aquifers
Authors: Rey A.. , Taware S. V. , Datta-Gupta A..
Published: February 2011

The effects of heterogeneity in Carbon Capture and Storage (CCS) in saline aquifers have been investigated extensively and are known to have important bearings on the storage capacity of the aquifer. In CCS projects, the time-lapse seismic survey has been proposed as a valuable tool for monitoring of CO2 movement. However, the potential of the time-lapse seismic data for heterogeneity characterization and geologic model updating has not been fully explored. One of the biggest challenges in the quantitative use of time-lapse seismic data during CCS is the complex movement of the CO2 influenced by compositional effects, geochemical reactions, phase changes and gravity segregation.

In this paper, we first introduce compositional streamlines to understand and visualize the flow and transport of CO2 in the presence of mineral precipitation/dissolution, residual trapping and buoyancy effects. To start with, individual component fluxes are generated by a finite difference fully implicit compositional simulator incorporating all the relevant physics of CO2 sequestration. The fluxes are then utilized in novel streamline tracing algorithms to generate phase and component streamlines depicting the movement and the trapping of CO2 in the aquifer. Next, we utilize the compositional streamlines to determine the sensitivity of the time-lapse seismic attributes specifically, interpreted saturation differences, to changes in reservoir properties such as permeability and porosity. The sensitivities are then used in an inverse modeling algorithm to calibrate the geologic model to time-lapse seismic data. The outcome is an improved description of permeability heterogeneity that is consistent with the 4-D seismic response and improved predictions of the CO2 storage capacity.

We have investigated the benefits of time-lapse seismic data integration in improving the performance assessment of CO2 sequestration using examples involving CO2 injection under realistic conditions. The first example examines the value of the 4-D seismic data integration in the estimation of storage capacity. The second example systematically studies the impact of viscous to gravity ratio on the performance of time-lapse seismic monitoring and heterogeneity characterization during CCS.