bluuebunny/crossref_metadata_2025 huggingface dataset:
Structural Characterization of Gas Shales on the Micro- and Nano-Scales
Authors: Curtis M. E.
Published: February 2011

The structure of shale samples from 9 different formations, the Barnett, Woodford, Eagle Ford, Haynesville, Marcellus, Kimmeridge, Floyd, Fayetteville and Horn River, has been investigated on the micro- and nano-scales using a combination of focused ion beam (FIB) milling and scanning electron microscopy (SEM). Using the FIB, a 10 nm thick cross-sectional slice (5 μm tall by 5 μm wide) is made into the shale. The newly exposed cross-section surface is then imaged using the SEM; this process is then repeated 300 - 600 times with each new slice progressing 10 nm deeper into the shale. The SEM images from this process form a 3-dimensional data set which is used to reconstruct a volume of the sectioned shale material. The reconstructed shale volumes show significant variations in the micro-structure (mineral content, micro-texture, clay platelet distribution, porosity, etc.) depending on the shale. Of particular importance to gas production is the variation in kerogen content and porosity within each shale. Assigning gray scale ranges to features, volumes can be constructed which show three dimensional distributions of these features. Some shale samples show significant kerogen content with connectivity of the kerogen observed throughout the reconstructed volume. Porosity in the shale samples is observed to be prevalent in either the kerogen, inorganic matrix, or both depending of the origin of the shale. When present, the kerogen in some shales has been found to have porosities of up to 50%. Observed pores within the shale samples range from a few to hundreds of nanometers in diameter, and the cross-sectional geometry of the pores varies depending on whether the pores are located in the kerogen or the inorganic matrix. Furthermore, the calculated porosity from the reconstructed shale volumes varies among the different shales. In addition to the calculated porosity, initial results for pore size distributions extracted from the reconstructed shale volumes will be presented in comparison to those found by mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) measurements. The SEM observed dimensions require consideration of new flow mechanisms for the transport of gas through shale.
Service Company Regulatory Issues in Unconventional Resource Play Exploration and Development
Authors: Theriau Rick
Published: February 2011

After the discovery of a new oil or gas play, many companies typically focus on both the potential of the resource and its development. Engaging the various interest groups who may have had previous use or aspirations for this area of land is often a forgotten consideration. The interests of these groups should be evaluated, and the groups should be involved to ensure that the development can proceed seamlessly. This consideration includes the careful planning of local regulatory and logistical issues while preparing for exploration and the subsequent development program of the unconventional resource.

A major oilfield company has operations that support unconventional resource development in Canada and has experience with the critical issues in these areas. This paper reviews operational considerations from a regulatory, personnel, infrastructure, and development-requirement perspective of an integrated service provider.

Key concepts include the following:

Stakeholder engagement, including indigenous people, regulatory bodies, landowners, and sub-surface competitors Personnel recruitment, orientation, training, and competency Hours of service and work scheduling for employees Facility, support, and equipment requirements Supplier network, procurement and logistics, and transportation of consumable items Considerations for sustainability and life cycle of the field Environmental effects and mitigation plans

As each of these areas is developed, specific issues can be resolved by the use of industry-sector associations and industry working groups to clarify and communicate expectations, thus leading to the codes of practice that may be required to develop the new technologies and techniques to enter into an unconventional resource play.
Reserves Management: A Concerted Effort
Authors: McMahan Nathan , Munoz Efren
Published: February 2011

Traditionally reserves management has been an exclusive function for Reservoir Engineers; however in mature fields the need to involve Production, Facilities, Geology, Operations Engineers and Financial Analysts is critical. This paper presents a suggested workflow to improve the way reserves are evaluated, supported, booked and documented with a concerted effort of a multidiscipline team. This paper is focused on tight gas reservoirs and the central idea is to reduce the uncertainty that is always present when dealing with reserves.

Most of the discussion is concentrated in understanding and verifying the hyperbolic decline “b” factor to be used for production decline analysis; we normally understand the mathematical meaning, but very rarely spend the time understanding the physical meaning and the consequences of using the wrong value. Once the “b” factor is defined, the proper documentation must be filed for each reserve record and the focus becomes the economic analysis of those reserves which is critical for future development especially in a very volatile economy in which prices are fluctuating a lot.
CCS: Opportunities and Obstacles for India
Authors: Raj P. , Mathur B. , Kumar S. , Jhalani S.
Published: February 2011

Carbon Capture and Storage (CCS) has become a popular catch phrase, both in scientific arena as well as on the political discussion. India, a country with a rapidly growing economy, where rise in economic growth goes hand in hand with an increase in energy demand which is currently met, as in many evolving economies, by fossil fuels. This ultimately leads to increase in GHG emissions. With the imminent threat of anthropogenic climate change in the coming decades, helping to control India's emissions will have to be a global priority. CCS can play a pivotal role in curbing India's emissions in the future, given its reliance on coal power and the large coal reserves. The main objective of this paper is to increase the understanding of the opportunities, issues and obstacles amongst the stakeholders regarding CCS in India. To achieve this objective, we have analyzed economic and institutional factors which encapsulate Indian power sector, challenges associated with the implementation of CCS, uncertainties linked with potential Co2 sources and sinks in India, needs and requirements for the future potential implementation of CCS in India. We have concluded our paper with relevant recommendations for the International Climate and CCS community to make conditions conducive for CCS in India.
Differences and Similarities in the Stimulation and Production of Shale Gas Reservoirs and Other Tight Formations
Authors: Economides M. J. , Wang X.
Published: February 2011

Production mechanisms and reservoir characteristics differentiate significantly in the exploitation of shale gas and other tight gas formations. In both cases, the use of massive hydraulic fracturing is essential and the reservoir characteristics, which include low to very low permeability (0.1 to 0.0001 md or even less), suggest very long and narrow fractures. It is clear that the choice of slick-water as fracturing fluid and the use of very small mass of proppant by the industry are the appropriate practices.

However, in tight reservoirs, gas is found in the pore space, requiring adequate porosity, and the initial gas-in-place (IGIP) can be readily calculated. Given the fractured well flow characteristics, recovery can then be estimated. Fracture design, taking into account the reservoir permeability, can be optimized to maximize the productivity index and ultimate recovery.

For shale gas, the IGIP is primarily in the form of adsorbed gas and far less of it is in the pore space. The volume of gas depends on sorption constants which describe the Langmuir adsorption/desorption isotherms. Because these constants are given in terms of gas per reservoir volume, the "stimulated volume," in other words, the volume contacted by the induced fractures, becomes critical. That is why horizontal wells with multiple transverse fractures, the latter with branches, have become the obvious geometry for shale gas production.

We present predictive models for production of both tight and shale gas reservoirs which include appropriate fracture designs taking into account reservoir characteristics. We also forecast well performance by considering well deliverability and ultimate recovery. The recovery for shale gas primarily depends on desorption. The results show distinct differences in production characteristics between tight gas and shale gas wells with the latter exhibiting far larger recoveries and sustainable production for far longer periods for similar reservoir permeabilities.
Numerical Simulation of the Solvent Drainage Process
Authors: Wong A. , Edmunds N.
Published: February 2011

Numerical simulations are widely used to predict and history match performance of reservoirs operating under various recovery processes. Simulators can offer quick answers however the answer should be validated against experimental/field data to verify its reliability. Many studies have been conducted to validate SAGD simulation results, but applying thermal simulators to solvent processes with confidence requires more studies and comparisons.

This paper will discuss the following topics on simulation of solvent process:

Comparing simulation results against the Nenniger and Dunn correlation on warm solvent drainage process Identifying the key input parameters(s) in solvent simulation Effects of grid block sizes on the results of solvent simulation

Nenniger and Dunn correlation (2008) provides good estimates of laboratory scaled simulation. Nenniger and Dunn recently mentioned the importance of rate limiting step and thickness of the solvent contact layer in the solvent drainage process. In order to understand the sensitivities of solvent simulation to the rate limiting step and thickness of the solvent contact layer, input parameters and grid block sizes were modified to observe their effects on the process.
Flow Regime Transfer Conditions for Two-Phase Flow in a Fracture
Authors: Shad S. , Maini B. B. , Gates I. D.
Published: February 2011

Overall, oil-laden fractured-rock reservoirs contain between 25 and 30 percent of the total known global petroleum reserves. In these reservoirs, fractures are the dominant flow path, therefore economic oil recoveries from fractured reservoirs rely on better understanding of the flow in fractures and networks of fractures. However, in contrast with gas-liquid flow in fractures, the flow of heavy oil and water has received less attention. Particularly, the flow regime map for two-phase immiscible flow in a thin gap and the transition boundaries are not well studied yet. In this research, a Hele-Shaw apparatus was used to study the flow of water in the presence of heavy oil in a smooth walled fracture. Different flow patterns were observed under different flow conditions and the effects of different fluid and fracture properties on flow regime transition boundaries for a thin gap were evaluated. The results of the experiments demonstrate that, flow regime boundaries strongly depend on fluid and fracture properties. The results also reveal that one correlation can be applied to predict different transition conditions under different fracture orientation.
Net CO2 Stored in North American EOR Projects
Authors: Faltinson J. E. , Gunter W. D.
Published: February 2011

One promising method for reducing CO2 emissions by storing the CO2 in oil reservoirs is CO2 Enhanced Oil Recovery (EOR). In order to make a significant contribution to mitigating climate change from emissions of GHG's, CO2 EOR must actually reduce CO2 emissions by storing net positive volumes of CO2. This requires that CO2 EOR schemes store more CO2 in the subsurface than the execution of the project emits (net positive storage of CO2). Fugitive emissions associated with CO2 EOR include primarily the burning of fossil fuels (fuel gas) to power CO2 injection compressors and the on-site consumption of electric power which results in CO2 emissions off-site where the power was generated. Evaluating the effectiveness of CO2 EOR in reducing CO2 emissions must be conducted in an unbiased way where only relevant fugitive emissions that are directly connected with the CO2 EOR project are deducted. It has been suggested that fugitive emissions from downstream oil refining and consumption of the transportation products should be deducted from the net CO2 stored by CO2 EOR projects. This presumes that these emissions (refining & consumption) are incremental to the EOR project and would not occur if the EOR project was not executed. World oil production is determined by world oil demand and if CO2 EOR projects were not undertaken, some other source of oil would step forward and fill the gap. Therefore, shutting down CO2 EOR projects will not lead to a decrease in incremental refining and consumption emissions. When downstream refining and product consumption fugitive emissions are correctly excluded from the calculation of Project Life-cycle CO2 EOR storage, it is clear that CO2 EOR does result in net positive CO2 storage.
An Unconventional Rate Decline Approach for Tight and Fracture-Dominated Gas Wells
Authors: Duong A. N.
Published: February 2011

Traditional decline methods such as Arps’ rate-time relations and their variations do not work for super-tight or shale gas wells where fracture flow is dominant. Most of the production data from these wells exhibit fracture-dominated flow regimes and rarely reach late-time-flow regimes even over several years of production. Without the presence of pseudoradial and boundary-dominated flows (BDF), neither matrix permeability nor drainage area can be established. This indicates that matrix contribution is negligible compared to fracture contribution and the expected ultimate recovery (EUR) can not be based on a traditional concept of drainage area.

An alternative approach is proposed to estimate EUR from wells where fracture flow is dominant and matrix contribution is negligible. To support these fracture flows, the connected fracture density of the fractured area must increase over time. This increase is possible due to local stress changes under fracture depletion. Pressure depletion within fracture networks would reactivate the existing faults or fractures, which may breach the hydraulic integrity of the shale that seals these features. If these faults or fractures are reactivated, their permeabilities will increase, facilitating enhanced fluid migration. For fracture flows at a constant flowing bottomhole pressure, a log-log plot of rate over cumulative production vs. time will yield a straight line with a unity slope regardless of fracture types. In practice, a slope of higher than unity is normally observed due to actual field operations, data approximation and flow regime changes. A rate-time or cumulative production-time relationship can be established based on the intercept and slope values of this log-log plot and initial gas rate.

Field examples from several super-tight and shale gas plays for both dry and high liquids gas production were used to test the new model. All display the predicted straight line trend, with its slope and intercept related to the type of fractured flow regimes. In other words, a certain fractured flow regime or a combination of flow types that dominate a given area or play due to its reservoir rock characteristics and/or fracture stimulation practices all produce a narrow range of intercepts and slopes. An individual well performance or EUR can be derived based on this range if the best-three-month average or the initial production rate of the well is already known or estimated.

The results show that this alternative approach is easier to use, gives a reliable EUR, and can be used to replace the traditional decline methods for unconventional reservoirs. The new approach is also able to provide statistical methods to analyze production forecasts of resource plays and to establish a range of results of these forecasts, including probability distributions of reserves in terms of P90 (lower side) to P10 (higher side).
Linking Reservoir Simulators with Fracture Simulators
Authors: Miranda Carlos , Soliman M. Y. , Settari A. , Krampol Radim
Published: February 2011

Reservoir simulation is currently used as the primary technique to simulate the behavior of almost all types of hydrocarbon reservoirs. Although several techniques have been developed to simulate the behavior of hydraulic fractures in reservoir simulators, a lack of accurate modeling of fracture geometry and fracture-fluid leakoff, as well as some other effects on hydraulic fractures (e.g., non-Darcy flow, dynamic fracture-conductivity behavior, stress-permeability dependence), is commonly observed in commercial-reservoir simulators.

A different approach is presented in this paper to fill the gap between reservoir simulators and hydraulic fracture simulators. Software capabilities have been developed to import propped-fracture geometry, proppant-area concentration, and fracture-fluid leakoff from commercial, grid-based fracture simulators, into a reservoir simulator with capabilities to model multiphase, non-Darcy flow inside the fracture. This includes the effects of long-term dynamic conductivity, stress-permeability dependence, and condensates banking, etc. This functionality permits better modeling of fracture-flow behavior and gives better insight into the cleanup and productivity of fractured wells, which will in-turn allow the user to design better fractures.
Barnett Shale (Mississippian), Fort Worth Basin, Texas: Regional Variations in Gas and Oil Production and Reservoir Properties
Authors: Tian Y. , Ayers W. B.
Published: February 2011

In 2007, the Barnett Shale in the Fort Worth basin of Texas produced 1.1 trillion cubic feet (Tcf) gas and ranked second in U.S gas production. Despite its importance, variations of reservoir properties and their effects on well performances have not been assessed. Therefore, we evaluated production statistics for the 5 Barnett production regions, and to assess controls on Barnett Shale production rates and fluid composition, we related production to completion method, reservoir interval completed, reservoir properties and geologic setting.

In all five production regions, horizontal wells produce approximately twice as much oil and gas as do vertical wells. First Year gas production of horizontal wells (P50) ranges from 30 to 350 MMcf. First Year oil production from horizontal wells ranges from 0 to 8,000 bbl. There are positive relations between the reservoir units perforated and production rates and volume, but there are no obvious monotonic relations between perforation interval thickness and Peak Monthly or First Year oil or gas production. After filtering the wells by the number of fracture and acid treatments, we did not observe any relationships between production and perforated interval thickness.

On the basis of petrophysical characteristics from 800 well logs, we divided the Barnett Shale into 4 reservoir units that are significant to engineering decisions and reservoir performance. The most productive wells are perforated in Reservoir Units 2, 3 and 4, inclusive. Reservoir Unit 1 is a shaly interval that has a hot gamma ray response and is rarely perforated. Reservoir Unit 2 is laminated, siliceous mudstone and marly carbonate zone. Reservoir Unit 3, the most commonly perforated Barnett reservoir unit, is composed of multiple, stacked, thin, upward coarsening sequences of brittle carbonate and siliceous units interbedded with ductile shales. Reservoir Unit 4, the upper Barnett Shale, is composed dominantly of shale interbedded with upward coarsening, laterally persistent carbonate and siliceous units, similar to Reservoir Unit 3.

This research should provide operators with a better understanding of Barnett Shale geologic and reservoir properties and assist with optimizing development strategies and gas recovery. The results may be applicable to other developing shale gas plays.
Microseismic Moment Tensors: A Path to Understanding Growth of Hydraulic Fractures
Authors: Baig Adam M. , Urbancic Ted , Prince Marc
Published: February 2011

Event locations and magnitudes are the first-order quantities of interest in reporting the observations of a microseismic monitoring program. From this, interpretations can be made from the geometry of the microseismic cloud as to the efficiency of the treatment and the appropriateness of various fracture-mechanical models. Moment tensors add another layer of understanding to these processes. The moment tensor of a microseismic event is a representation of the mechanism responsible for the observed radiation of seismic energy. The moment tensors can help understand the states of stress and strain induced by the treatment, as well as giving insights into the geometry of the fracture network. Additionally, as these moment tensors can identify volumetric change, we have the opportunity try to correlate these mechanisms with the injection parameters and obtain a glimpse into how and where the medium is responding to the treatment.

We present the results of a microseismic monitoring study where the moment tensors have been determined. This study involves recording microseismicity from multiple sensor arrays where a number of good quality events were recorded.

The higher-order moment tensor analysis of these data show how the fracture is growing with the treatment. The distribution of moment tensors usually falls along a trend line between the mechanisms characteristic of crack-opening to crack-closure type events. The distribution of these crack-opening and closing events though time and space, and in relation to the parameters of the injection treatment, suggest how that the fractures grow with crack-opening events at the tip. The closure events occur behind the opening events, both temporally and spatially, and indicate that there is a flow of injectant throughout the volume.

Based on these analyses, we suggest that moment tensor solutions for microseismic events can be used to calibrate models of hydraulic fractures and other injection programs. Exploitation of these data will add to the insight gained from microseismic monitoring.
Unconventional Resource Assessment of the Montney Formation in Alberta
Authors: Anderson S. D. , Rokosh C. D. , Beaton A. P. , Berhane M. , Pawlowicz J.
Published: February 2011

The ERCB/AGS has collected data 293 core samples from the Montney Formation in Alberta and run a series of geochemical and geological tests to characterise the formation for resource assessment. The goal of this talk is to discuss the regional distribution of the data and its significance to unconventional gas production in Alberta. The data will be used for an unconventional gas resource analysis of the Montney.

The geochemical and geological tests include adsorption isotherms, Rock Eval/TOC, organic petrography, vitrinite reflectance, XRD whole rock and clay mineralogy, SEM imaging, thin section analysis and imaging, porosimetry, permeametry, and pycnometry. We will present maps and graphs of adsorbed and free gas content, thermal maturity, TOC, net silt and shale, porosity feet, mineralogy and grain density variations. The work we do will help to bridge the Alberta Montney knowledge gap and possibly spur interest in the area.

This presentation will focus on the geochemical characteristics of the Montney Formation as they relate to resource assessment. A few of the key factors influencing shale gas resource assessment include TOC, thermal maturity and adsorbed gas content. Samples we have collected have shown TOC ranges from 0.06 to 3.64 wt percent (Figure 1) and vitrinite reflectance values between 0.31 and 2.45. Through mapping and graphing we will analyse these results and their distribution. In addition, we will compare the adsorbed gas content versus the free gas content. Lastly, log porosity varies with grain density. In the Montney, grain density varies with the amount of dolomitisation. Mineralogy-derived grain density calculations (Table 1) will be presented to show spatial and temporal distribution and hence porosity.
A Gas Production System From Methane Hydrate Layers by Hot Water Injection and BHP Control With Radial Horizontal Wells
Authors: Yamakawa T. , Ono S. , Iwamoto A. , Sugai Y. , Sasaki K.
Published: February 2011

A gas production system from methane hydrate (MH) sediment layers by combination method with hot water injection and bottom hole pressure control at production well using radial horizontal wells has been proposed.

Firstly, gas production characteristics by the depressurization method with bottom hole pressure control have been evaluated by numerical simulations of cylindrical homogeneous MH layer model. The cumulative production gas amount or MH recovery ratio were limited with the pressure reduction from MH equilibrium pressure, because the sediment pressure must be suppressed to keep mechanical stability of sediment layers under the sea bottom. Furthermore, effects of numerical bock modeling and averaging physical properties of MH layers have been discussed as those numerical simulation errors against the original deposit model show a safety side results to evaluate economic issues in gas amount and production rate.

By applying the present production system with combining hot water injection and bottom hole pressure control, the numerical simulation results showed that dissociated region including two wells filled with hot water, named as hot water chamber, is expanded outer ward from the area center of MH layer with continuous gas production. The simulations on gas production by injecting 85°C hot water into the MH layer with 1km× 1km and 20m in thickness by using four pairs of dual horizontal wells 500m in length were carried out. It was found that 2MPa pressure reduction from MH equilibrium pressure made the gas production 2.2 times compared with the case of hot water injection only without pressure reduction control.
A Novel Injection Well String Design to Accelerate CO2 Dissolution in Deep Saline Sequestration
Authors: Shafaei M. J. , Abedi J. , Hassanzedeh H. , Chen Z.
Published: February 2011

Geological storage of carbon dioxide (CO2) is one of the proposed strategies for mitigation of global warming. The CO2 injected into saline formations has less density than that of the resident formation brine. The injected mobile supercritical phase migrates upward and spreads under the sealing rock, due to its buoyancy. While CO2 is in the free mobile phase, there is always a risk of leakage through natural and artificial pathways. Once CO2 is dissolved into brine, it cannot migrate upwards other than by diffusion; and, it can then be retained with a minimal risk of leakage. Therefore, solubility trapping could enable more secure storage.

The objective of this study is the proposal of a CO2 injection well string to increase CO2 dissolution in brine and thereby reduce the risk of leakage of the injected CO2. The proposed well string configuration employs a tubing annulus system equipped with gas lift valves: The supercritical CO2 is injected through the annulus, and fresh brine is injected through the tubing. The designed flow rate of the injected CO2 through gas lift valves enhances dissolution of the CO2 into the injected brine.

A simplified single-phase mechanistic model is developed, and analytical solutions of the governing equations are obtained. Using the developed model, the dissolution of CO2 into brine is characterized by governing dimensionless numbers, such as the Peclet and Sherwood numbers. Scaling relations are presented and can be used to investigate the mixing performance under various operating conditions.
Integration and Technology Options for Implementing CO2 Capture and Storage in Oil Sands Operations
Authors: Ordorica-Garcia G. , Carbo M. , Nikoo M. , Bolea I.
Published: February 2011

The majority of the technology development for CO2 Capture and Storage (CCS) is driven by the electric utility industry, where the emphasis is on large centralized units for electric power generation with coal as the primary fuel. The implementation of CCS in oil sands operations has significant potential to provide meaningful carbon emissions reductions. This paper presents various concepts for integrating leading CO2 capture techniques to bitumen extraction and upgrading processes. The main carbon capture technologies are reviewed and their relative advantages and disadvantages for implementation in bitumen mining, thermal bitumen extraction, and upgrading are discussed, leading to a qualitative assessment of their suitability for each oil sands process.
Integrated Reservoir and Decision Modeling to Optimize Spacing in Unconventional Gas Reservoirs
Authors: Turkarslan G. , McVay D. A. , Bickel J. E. , Montiel L. V. , Ortiz R. R.
Published: February 2011

Despite our increased experience, unconventional gas plays remain risky. In the face of this risk, operators must balance the need to conserve capital and protect the environment by avoiding over drilling with the desire to maximize profitability by achieving the optimal well spacing as quickly as possible. Previous unconventional gas developments such as the Carthage Field (Cotton Valley) have implemented multiple infill drilling programs over several decades to optimize well spacing, with significant reduction in value (McKinney et al. 2002). However, in emerging plays such as the non-core Barnett Shale and the Fayetteville Shale, historical infill programs are not available to evaluate optimal spacing and we do not have the luxury of developing these fields over the next 30-40 years. Existing approaches for optimizing development, such as integrated reservoir simulation studies or statistical moving-window methods, can be either prohibitively time-consuming and expensive or they do not consider the uncertainty inherent in the assessment.

The objective of our work was to develop technology and tools to help operators determine optimal well spacing in highly uncertain and risky unconventional gas reservoirs as quickly as possible. To achieve the research objectives, we developed an integrated reservoir and decision modeling system that incorporates uncertainty. We used Monte Carlo simulation with a fast, approximate reservoir simulation model to match and predict production performance in unconventional gas reservoirs. Simulation results are then integrated with a Bayesian decision model that accounts for the risk facing operators. We applied these integrated tools to a hypothetical case based on data from Deep Basin (Gething) tight gas sands in Alberta, Canada, to determine optimal development strategies.

We anticipate that the tools and methodologies developed will be applicable in most shale and tight gas reservoirs. These tools should ultimately be able to help operators determine, for example, the combination of primary development strategy (well spacing and/or completion method) and testing (pilot downspacings and/or tests of other completion methods) that maximizes future profitability. The optimal design of such programs in unconventional reservoirs, where the risks are high, is likely to pay large dividends.
Improved Proppant Transport System for Slickwater Shale Fracturing
Authors: Kostenuk N. , Browne D. J.
Published: February 2011

The primary purpose of stimulating shale reservoirs is to extend drainage radius by connecting natural fractures, thus maximizing Stimulated Reservoir Volume (SRV). A conventional proppant transport system relies on the viscosity of the fracture fluid to suspend and transport the proppant further into the formation. With the development of unconventional plays, shale gas reservoirs are being treated with slick water type treatments that have inherent low fluid viscosity. Slick water shale fracturing uses proppant transportation that depends on turbulent flow, sand banking and/or bed transport. These result in the majority of the proppant being deposited on the bottom of the created fracture, close to the wellbore, leaving a large portion of the created fracture length unpropped.

In trying to improve proppant transportation, many have focused their efforts on either reducing proppant size or density, both of which will lower proppant settling rates according to Stoke's Law. However, using smaller proppant sizes or expensive but lower strength lightweight proppants can result in lower fracture conductivities.

This paper examines a new proppant transport method that significantly reduces proppant settling and proppant banking in slick water shale fracturing treatments. This unique technology is based on modifying the surface property of proppant on-the-fly, where micro-bubbles are formed on the surface and around each proppant grain. These micro-bubbles change the buoyancy of the proppant granules. The proppant can therefore be transported in slick water, traveling further distances into the formation without settling, independent of gel viscosity.

Presented experimental data in this study is supported through lab studies, which include conductivity cell, core flow and proppant pack testing. Several tests were performed to examine and illustrate the proppant transport properties of this technology under simulated field conditions. This study also includes reservoir modelling, comparing well productivity with proppant distribution from bed load transport with the new proppant transportation system.
Improving the Performance of Vapor Extraction of Heavy Oil and Bitumen Using the Warm VAPEX Process
Authors: Rezaei N. , Mohammadzadeh O. , Chatzis I.
Published: February 2011

The advantages of solvent-based enhanced oil recovery processes for production of heavy oil and bitumen have always been sacrificed with their low oil production rates and also high solvent costs. Attempts have been made to integrate the solvent and thermal processes to attain better recovery techniques in terms of improved oil production rate, oil quality, and material and energy requirements. In this paper, the process of warm VAPEX is introduced where the injected solvent is superheated. The temperature of solvent vapor (nC5), permeability of packed medium, and the viscosity of oil in place were considered as experimental factors. The VAPEX experiments were performed at 3 temperature levels (36, 43 and 50 °C) using Cold Lake bitumen and Lloydminster heavy oil at two permeability levels (220 and 830 Darcy). The performance of the warm VAPEX process was compared to that of the conventional VAPEX. The packed model was placed in an isothermal bath of circulating hot air to lower the heat loss to surrounding and also to avoid temperature variations of the environment between different trials. During the experiments, the live and dead oil production rates, solvent content analysis, asphaltene content analysis and also residual oil analysis were conducted. The production performance was enhanced, to some extent, when the solvent was allowed to condense, by lowering the temperature of the isothermal bath below the solvent dew point temperature. However, upon a moderate degree of superheating (i.e., the mid-level temperature of 43 °C), the bitumen production was substantially increased at both levels of permeability. The solvent content and solvent-to-oil ratio during the warm VAPEX process decreased with increasing the degree of superheat. Except for the warm VAPEX trial at bubble point temperature, the solvent-to-oil ratios were lower in the warm VAPEX, as compared to the baseline. The asphaltene content analysis showed insignificant deposition of asphaltene during the conventional VAPEX process in which condensation did not occur. On the other hand maximum asphaltene precipitation was achieved at the lowest temperature level (bubble point temperature). At a fixed level of permeability and initial oil viscosity, the residual oil saturation increased with the level of solvent superheating. Therefore, by applying optimal operating conditions, the oil production rate significantly increases while the solvent-to-oil ratio decreases as a result of decreased solubility of solvent in the bitumen. Both factors favor the economy of the VAPEX process. In-situ upgrading of the crude will also occur, which contributes to the improved quality of the produced oil.
Forecasting Tight Gas Well Production with a Material Balance Constraint
Authors: Morgan Michael
Published: February 2011

In SPE 133615, Nobakht et al. [1] introduced a simplified method of production forecasting for tight/shale gas wells which exhibit extended periods of linear flow. The method is simple as it relies principally on a plot of inverse rate versus square root time. In the present work, we extend this method by applying a material balance constraint that allows for changing reservoir pressure with depletion. We generate curves for a type well. These curves are normalized on the basis of the initial rate of the well. This work shows that wells from similar producing areas will all fit on the same "type curve".

The advantages of this forecasting method are: (1) It requires only the initial rate and an estimate of Original Gas in Place (OGIP), (2) The cumulative gas production can be calculated at any given time without the need to time-step forward and (3) it can be used as a field development planning tool, when combined with the economics of multistage hydraulic fracturing.
The Application of Solvent-Additive SAGD Processes in Reservoirs With Associated Basal Water
Authors: Peterson J. , Riva D. , Edmunds N. , Solanki S.
Published: February 2011

This paper describes the results of a simulation and optimization study on the application of a solvent-additive steam-assisted gravity drainage (SAGD) process to reservoirs with associated basal water. A review of related studies is provided, together with a discussion of the pros and cons of potential alkane solvents in basal water reservoirs. Economics and the impact of dynamic and ultimate retention are discussed.

A general conclusion drawn from literature is that optimal solvent application to SAGD in reservoirs will likely involve time variations in both rate and composition of the solvent. This is also the case for reservoirs with associated basal water. This results in an optimization problem that has a large number of dimensions, and is very nonlinear. Genetic algorithms, which mimic biological evolution, have been found to be extremely effective in addressing such problems.

A key product of this effort, optimized for a simple clastic reservoir with associated basal water, is presented. The study produced an operable process, which could be described as a new combination of pre-existing concepts. The process offers material improvements in thermal bitumen supply costs, as well as recovery factor. Major reductions in the physical steam/oil ratio (SOR), (and therefore) capital intensity, water use and carbon emissions, are indicated.
Experimental Evaluation of SAGD-ISC Hybrid Recovery Method
Authors: Oskouei S. J. , Maini B. , Moore R. G. , Mehta S. A.
Published: February 2011

Most of the current in-situ recovery methods have limitations which restrict their application in many heavy oil reservoirs. There are also a variety of undesirable environmental costs associated with the existing recovery techniques that limit their desirability. To overcome some of these issues, recent novel hybrid technologies have been proposed based on combining Steam Assisted Gravity Drainage and In Situ Combustion technologies. In the conventional ISC process, oil is displaced by an elevated temperature combustion zone but when the native oil mobility is not high enough this displacement becomes problematic. Warming up the reservoir and reducing the distance between injector and producer is needed to prevent liquid blocking inside the reservoir during the combustion process. This suggests that a well configuration that greatly decreases the distance between the injector and the producer would be advantageous in ISC based recovery methods and the well configuration used in SAGD comes to mind. Running SAGD in the initial periods creates a vapor-filled depleted zone in the reservoir which is hot enough to start combustion on air injection.

To investigate the possibility of this idea, a hybrid experiment was conducted at a representative reservoir pressure. During the experiment, SAGD was operated in the model for a period and then combustion was started by switching from steam injection to air injection. A well arrangement was considered to help process operation, oil ignition, and combustion front formation. Residual oil and water saturations in the model were analyzed. Also, core samples were extracted from the model to evaluate asphaltenes and coke formation. It was concluded that it is possible to recover almost 70% of the original oil in place with a special kind of well arrangement.
Defining Horizontal Well Objectives in Tight and Unconventional Gas Reservoirs
Authors: Britt L. K. , Jones J. R. , Miller W. K.
Published: February 2011

Horizontal wells have become the "industry standard" for unconventional and tight formation gas reservoirs. Because these reservoirs have poorer quality pay it takes a well planned completion and fracture stimulation(s) to make an economic well. Even in sweet spots in unconventional and tight gas reservoirs good completion and stimulation practices are required to achieve economic success. But what are the objectives of horizontal wells and how do we relate the completion and stimulation(s) to achieving these goals? How many completions/stimulations do we need for best well performance and/or economics? How do we maximize the value from horizontal wells? When should a horizontal well be drilled longitudinally or transverse? These are just a few questions to be addressed in this paper.

This paper focuses on some of the key elements of well completions and stimulation practices as they apply to horizontal wells. Economic optimization studies were conducted for tight gas reservoirs highlighting the importance of lateral length, number of fractures, inter-fracture distance, fracture halflength, and fracture conductivity. In addition to the tight gas completion and stimulation considerations, network complexity will also be considered. These results will be used to develop a horizontal well decision tree for evaluating the various drilling, completion, and stimulation issues encountered in horizontal wells in tight and unconventional gas reservoirs. Field examples will be used to highlight these strategies.

This work benefits the petroleum industry by:

Developing well performance and economic objectives for horizontal wells and highlighting the incremental benefits of various completion and stimulation strategies, Establishing well performance and economic based criteria for drilling longitudinal or transverse horizontal wells, Integrating the reservoir objectives and geomechanical limitations into a horizontal well completion and stimulation strategy, Developing a horizontal well completion and stimulation decision tree for pre-horizontal well planning purposes.
Front Self-Correction in the In-Situ Combustion
Authors: Oskouei S. J. , Moore R. G. , Maini B. , Mehta S. A.
Published: February 2011

Since it was discovered in the early 1900's, several improvements have been suggested for the in situ combustion technology. Top-down combustion displacement, is a process proposed for application with horizontal well technologies. In this configuration, air is injected near the middle of the reservoir, close to the overburden, through a horizontal well or a number of vertical wells. Fluids are produced from the reservoir through another horizontal well placed near the bottom of the reservoir. In this configuration, the combustion front moves downward in the gravity direction and displaces fluids to the production well.

Combustion front formation and its stability are major concerns in this arrangement. While the short distance between injector and producer addresses the cold oil blocking problem in the reservoir, it has the potential to create air fingers which could prevent stable advance of the combustion zone in a horizontal plane. Front self-correction must occur to prevent oxygen from fingering to the production wells.

To prove this idea, experiments at reservoir pressure were carried in a two-dimensional SAGD model with Athabasca bitumen. Air was injected into the SAGD steam chamber, from the middle, and fluids were produced from the bottom. Front advancing directions were monitored by a series of thermocouples located inside the model. It was found that combustion zone starts spreading horizontally in the model until it reaches a limiting point then it starts moving downward as a horizontal front. Despite heterogeneity of the oil saturation and relative permeability in the steam chamber and un-swept zones, the combustion front moved almost as a horizontal plane and no sharp fingers were recorded in the experiments. These experiments show that stable middle-down combustion is feasible.
Plunger Lift Optimization in Horizontal Gas Wells: Case Studies and Challenges
Authors: Sask D. , Kola D. , Tuftin T.
Published: February 2011

Plunger lift is a proven technique for lifting liquids from vertical gas wells flowing below critical velocity. The use of plunger lift in horizontal gas wells was not initially expected to provide any difficulties or challenges. While it has been relatively easy to make plunger lift function in horizontal wells, truly optimizing production has proven to be much more challenging.

One of the challenges of horizontal wells is moving liquids from the horizontal well bore to the tubing above the bumper spring assembly. To facilitate this bumper springs are landed as deep as possible, which creates operating challenges for both bumper springs and plungers. Bumper spring check valve limitations were identified at high deviation angles and re-designed bumper springs have been deployed to address this. Recent testing has shown that the efficiency of some plunger types can be significantly reduced when used in horizontal wells and the explanation for this decrease as well as the test results are provided.

Plunger control software development for the Sierra field's horizontal well application has led to increased production times and volumes. It has resulted in additional operational benefits that reduce down time caused by cold weather and pipeline pigging operations. The software is embedded into the SCADA control system and can utilize well parameters monitored within SCADA to vary the plunger control parameters.

This paper presents case studies showing the impact of plunger control software for horizontal wells. Case studies detailing operational performance benefits and the performance of various types of plungers in high angle applications are also presented. Additional case studies show the impact on plunger performance of well bore trajectory and liquid hold up in the horizontal well bore. Continuous improvements to strategies and operations have been implemented to fully optimize horizontal gas wells.