bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimization of WAG Process for Coupled CO2 EOR-Storage in Tight Oil Formations: An Experimental Design Approach
Authors: Ghaderi S. M , Clarkson C. R. , Chen S.
Published: October 2012

Restricted flow capacity of low permeability oil formations imposes unique challenges to the implementation of CO2-WAG processes in such reservoirs. Application of multi-stage fractured horizontal wells can substantially improve the injection and production rates. However, there are various design parameters and operating conditions which can affect the performance of a WAG flood. The parameters considered in this study are those related to development pattern (well spacing and well completion strategy), hydraulic fracture geometry (half-length and spacing), WAG parameters (WAG ratio and CO2 slug size) and the timing of the switch from primary or water-flood to WAG scheme. In this study, CO2 EOR performance is assessed based on the oil recovery factor and also the amount of stored CO2; in other words, the objective is to achieve both the goals of enhanced oil recovery and sequestration of CO2 in the tight oil formation. However, to reflect the effect of time, the net present value (NPV) of the projects was also considered. All three of these parameters were therefore included in objective functions to be optimized.

The effect of all aforementioned parameters on objective functions was investigated using a compositional simulator. Design of experiment (DOE) was then utilized to perform a comprehensive statistical analysis to recognize the most prominent factors in fulfillment of each objective function in a tight reservoir with properties similar to Pembina Cardium field. Response surfaces were generated to quantify the effect of the factors on the objective functions. Optimization was carried out to find those sets of factors which provided the highest recovery, storage, and NPV. Searching for optimal values can be extended to any combination of objective functions which are obtained by applying weighting multipliers to each individual objective function.
Application of Modern Horizontal Well Technologies to EOR Production Systems
Authors: Daneshy A. , Ardali M. , Ibragimov N. G. , Ibatullin R. R. , Mitchell R. K.
Published: October 2012

Modern horizontal well completion technologies consisting of cased or openhole wellbores and multiple hydraulic fractures have revolutionized production from very low permeability oil and gas reservoirs. This paper extends the application of these completions to production systems using thermal Enhanced Oil Recovery (EOR) processes. It reports the results of an extensive simulation study to evaluate the performance of different completion technologies using horizontal wells with and without multiple hydraulic fractures. The results indicate that combination of horizontal wells with multiple fractures increases access to the reservoir and enhances fluid injectivity, improves sweep efficiency and time, accelerates oil production rates and increases ultimate oil recovery.

Proposed production system is especially beneficial in reservoirs with high heterogeneity in fluid and rock properties. It lowers the risk of injected fluid channeling through high permeability segments and natural fractures; thereby improving the injection profile and reducing by-passing of the reservoir fluid. In addition, the paper provides completion recommendations for avoiding some of the operational issues that usually come up when considering horizontal wells, and, hydraulic fracturing for EOR systems.
Hydraulic Fracturing Optimization for Unconventional Reservoirs - The Critical Role of the Mechanical Properties of the Natural Fracture Network
Authors: Nagel Neal B. , Garcia Xavier , Lee Byungtark , Sanchez-Nagel Marisela
Published: October 2012

The success of many shale plays depends on the optimal stimulation of natural fractures, and the characterization of the natural fracture systems is a key issue often leading to the construction of a discrete fracture network (DFN). The DFN chiefly consists of fracture spacing, fracture dip, and dip direction from numerous sources, and, in some cases, is matched to well test data allowing for the determination of hydraulic properties. However, a commonly missing component of natural fracture characterization, and the component most important to evaluating the coupled hydro-mechanical behavior of the fractures during a hydraulic fracture stimulation, is the evaluation of the mechanical behavior of the fractures.

The important mechanical parameters of the fractures include: a) elastic properties such as shear and normal stiffness, which relate changes in pore pressure to changes in aperture; b) strength parameters such as cohesion and friction angle, which define when a fracture may shear and open; c) dilational properties, which relate fracture opening to shear slippage; d) fracture toughness, which determines the pressure required to extend a fracture; and e) initial aperture. In this paper, using a new, state-of-the-art, fully-coupled, 3D distinct element hydraulic fracturing simulator, mechanical fracture parameters were evaluated in a parametric study in order to determine their impact on the effectiveness of hydraulic fracture stimulations.
Integrated Microseismic Monitoring for Field Optimization in the Marcellus Shale - A Case Study
Authors: Neuhaus Carl W. , Williams-Stroud Sherilyn , Remington Christine , Barker William B. , Blair Keith , Neshyba Garrett , McCay Taylor
Published: October 2012

The work presented in this paper focuses on an integrative analysis of hydraulic fracture treatments conducted in the Marcellus Shale. The treatments have been monitored by a permanently installed array of buried geophones used to detect microseismic events. These event sets were analyzed in conjunction with available data from other sources, such as well logs and well cores, as well as information on reservoir properties, regional and local geology and other sub-surface structural information. Passive seismic data was acquired by an array of 101 permanently installed geophones buried and cemented in place at a depth of 150 ft in purpose-drilled boreholes covering an area of over 18 square miles providing high resolution stimulation monitoring. The permanent installation of geophones below the surface allows for significant increase in signal-to-noise ratio and consistent comparison of hydraulic fracture treatments for any given number of wells under the array footprint.

This integrative analysis determined how various factors related to the specific reservoir geology in the Marcellus and to what extent the variability of hydraulic fracture treatments impacted the microseismic results. The next step of the evaluation investigated the relationship between hydrocarbon production and the microseismic results, relative to changes in geology and variability of the stimulation approach.

Analysis of stress changes indicated by the microseismic source mechanisms was used to explain the asymmetry of microseismicity about the wellbore. Relationships and statistics of treatment options with respect to the monitoring results were investigated, including the modeled discrete fracture network, the modeled fracture volume, the stimulated reservoir volume, and the cumulative microseismic moment of the event set. The initial production (IP) was compared to reservoir and engineering parameters, such as treatment pressures, sequence of treatments (toe-to-heel vs. zipper-frac), net pressures, and stage spacing, to determine if the variability in the microseismic results is due to engineering differences or to spatially-varying reservoir properties. Simple well test simulations were performed to investigate different fracture and flow models, and compare results to the IP and available reservoir properties.
High Resolution Magnetotellurics for Petroleum Exploration and Development applied on the Unconventional Eagle Ford Shale Play, North of Mexico
Authors: Woods Daniel A. , Manriquez Lopez Alberto , Mecionis Robert J.
Published: October 2012

This paper presents the results of the first application of high resolution magnetotellurics, a passive electromagnetic (EM) method, for hydrocarbon exploration in an onshore project in the North of Mexico. In general, controlled source electromagnetic (CSEM) methods are used in combination with magnetotelluric surveys for mapping and imaging subsurface structures for exploration purposes offshore. In this onshore study, high resolution magnetotelluric instrumentation and a novel methodology were developed to capture and analyze frequencies from the naturally occurring electromagnetic waves returning to the surface from the subsurface of the earth. Since natural electromagnetic energy is being captured, magnetotelluric surveying utilizing surface generated higher frequencies satisfies the level of resolution required for depth of investigation, depth accuracy, and thickness resolution in Eagle Ford shale play. The recorded passive electromagnetic data were analyzed, and the raw EM signal demodulated to an audio format for analysis. The resulting audio signal was then interpreted to obtain an estimate of porosity from signal strength and character and fluid contents characteristics from signal phase changes.

The results were integrated and presented in electric log type format, base maps, and cross plots for interpretation, correlation, and identification of hydrocarbon trends along horizons. The main contributions of this work consist of the following. Firstly, our results will enormously contribute in reducing the uncertainty associated with seismic interpretation alone for petroleum exploration to generate new prospects and to validate existing ones. Secondly, as unconventional resources become increasingly important, identification of hydrocarbon bearing fracture and orientation using this technique will contribute to development plans for both: horizontal drilling planning and design and hydraulic fracturing.
Shear Wave Anisotropy Measurement from Azimuthally Focused LWD Sonic Tool
Authors: Mickael Medhat , Barnett Craig , Diab Mohamed
Published: October 2012

A new logging-while-drilling (LWD) logging tool has been developed to measure shear wave anisotropy and provide a wellbore acoustic image. The tool consists of a focused transmitter and six focused receivers. The transmitter fires rapidly and waveforms are acquired in the six receivers as the tool rotates in the borehole. Sixteen azimuthal waveforms are acquired for each receiver and processed to produce compressional and shear velocities of the formation as a function of azimuth.

Anisotropy ratio and maximum/minimum stress directions are determined from the velocity images. Borehole images of the compressional and shear velocities of the formation are also obtained from the azimuthal velocities. This paper shows modeling data of the tool response in different anisotropic formations to assess the accuracy and viability of the measurement. The ability of the measurement to determine formation anisotropy at different borehole inclinations and the sensitivity of the borehole image to the formation acoustic properties are also discussed. Field examples of the anisotropy measurement and the borehole images obtained in vertical, deviated, and horizontal wells are presented.
A Novel Potassium Silicate for Use in Drilling Fluids Targeting Unconventional Hydrocarbons
Authors: McDonald Michael
Published: October 2012

The challenging nature of drilling and producing shale gas plays has favored the use of oil-based drilling fluids. The growing importance of shale gas has placed greater pressure to address environmental issues associated with the drilling and production of these wells. A pressing goal is the development of a highly inhibitive and environmentally friendly water-based drilling fluid. Specifically, the drilling fluid should address wellbore stability issues associated with specific shale gas plays. Such specialized drilling fluids will better stabilize shales and help control drill time and costs.

This paper discusses the research and development of a novel potassium silicate as a shale stabilizer for certain shale gas plays. This novel potassium silicate differs from conventional potassium silicate by significantly increasing the level of dissolved silicate to potassium. The resulting potassium silicate is chemically more reactive and can more easily undergo the polymerization and precipitation reaction. These reactions are the shale stabilization mechanisms most often associated with sodium and potassium silicate. Laboratory investigation indicates drilling fluids formulated with this more vitreous potassium silicate show a high degree of effectiveness at preventing shale delamination and sealing micro fractures.

Drilling fluids formulated with conventional potassium silicate can often be disposed using surface methods such as mix-bury-cover, land spreading or land spraying. However, depending on receiving soil or the concentration of potassium silicate in the drilling fluid, it sometimes becomes necessary to treat the associated drill waste with a calcium-based amendment or send the waste to an approved waste management facility. The reduced alkalinity and more siliceous nature of high ratio potassium silicates provides for a drilling fluid with lower salinity as measured by electrical conductivity and sodium adsorption ratio. Resulting drill waste can more easily meet the salinity requirements associated with using surface disposal methods.
Hydraulic Fracturing Design and Its Effects on Oil Recovery in Bakken Formation
Authors: Chen Shengnan , Wang Xiaoqi
Published: October 2012

Development of tight or low permeability reservoirs (e.g. Bakken formation) commences to reveal its potential and significance and expected to become even more essential in the future. The Canadian Bakken has been produced for over 40 years. At present, the combination of horizontal well drilling and the new multi-stage fracturing and completion technologies has been the key to economically unlocking the vast reserves of the Bakken formation. Parametric studies of fracture geometry on well productivity and oil recovery are essential for a successful hydraulic fracturing stimulation treatment. In this paper, we will investigate the best hydraulic fracturing scenario for Bakken formation and the effects of fracture geometries on oil recovery. More specifically, a geological model is firstly built using typical fluid and rock properties in Bakken formation; the horizontal wells with multistage hydraulic fractures will then be modeled using local grid refinement (LGR) and history matched based on the field production data. Various fracture treatment designs are evaluated, which include the investigation of various fracture spacing, lengths, and fracture locations on the horizontal wells. The results of this study show that, employing multistage hydraulic fracturing along horizontal wells can significantly improve oil recovery in Bakken formation. Compared to fracture length, fracture spaces or fracture numbers have greater impacts on oil recovery. More importantly, for the same fractured volume in the reservoir (i.e., the same usage of proppant and fracturing fluid), fractures with longer and smaller fracture numbers lead to a similar oil recovery compared to shorter but larger fracture numbers along the horizontal well laterals.
Minimum Horizontal Stress Profile From Logging Data for Montney Formation of North East British Columbia
Authors: Song Lisa , Hareland Geir
Published: October 2012

Microfrac or fall off injection test is a technique used to accurately measure minimum horizontal stress directly in the formation. However, other than being expensive and time consuming, this test does not give a continuous minimum horizontal stress profile. Continuous minimum horizontal stress profile is especially important for hydraulic fracturing design for the tight Montney formation. This study utilizes logging data and core reports to generate the minimum horizontal stress profile for two Montney wells in North East British Columbia. Specific value of tectonic stress determined from injection fall off analysis is also included in the calculation.

The first method, conventional method, calculates minimum horizontal stress by solving linear poroelasticity equations with vertical stress equal to the overburden. Closure pressure from fall-off injection test is used as a calibration point to acquire tectonic stress. The second method incorporates the tectonic, thermal effect and rock mechanical properties at each incremental depth to generate the minimum horizontal stress. The third method, vertical transverse isotropy (VTI), is conducted assuming different rock properties on the vertical and horizontal direction and also different tectonic strain for the maximum and minimum direction.

The conventional method yields the lowest minimum horizontal stress magnitude without any distinctive characteristic. On several zones, the VTI method shows higher stress magnitude above Montney and reveals some good zone containment for hydraulic fracturing design, which the conventional method does not provide. From the injection fall off analysis, a second closure pressure with lower value than the first closure is believed to represent the overburden stress. It is concluded that this area has a thrust fault regime in which overburden stress is the least principle stress.
An NMR Study of Shale Wettability and Effective Surface Relaxivity
Authors: Sulucarnain Ismail , Sondergeld Carl H. , Rai Chandra S.
Published: October 2012

Traditional methods of determining wettability such as the Amott and the U.S. Bureau of Mines (USBM) test for an oil/brine/rock system are difficult to apply to shales due to their extremely low permeability, usually in the nanodarcy range. Earlier Nuclear Magnetic Resonance (NMR) studies on Berea sandstone showed consistency with standard wettablity measurements and served as a calibration standard. A total of 10 core plugs from an Ordovician organic rich shale were analyzed. The T2 NMR signature of the imbibed dodecane and brine occurred mostly at relaxation times faster than their measured bulk relaxation of 1 and 3 second, respectively, indicating that surface relaxation is dominant. The Ordovician organic rich shale display mixed wettability. Three of the samples had a high affinity for dodecane, as a result of the organic pores present in the samples. This result was consistent with the NMR spectra in both sequences as well as the gravimetric analysis. The main advantage NMR has over the traditional methods is that we are able to see where the fluids are being imbibed.

Mercury injection capillary pressure (MICP) characterizes the distribution of pore throats while NMR responds to the pore bodies. Assuming the throats and bodeies are equivalent, a scaling factor was used to match the NMR spectra and the MICP curves to estimate the effective surface relaxivity for the shale samples. The range of the effective surface relaxivities ranged between 0.5μm/sec to 3.1μm/sec with an average of 1.7 ± 1.0 μm/sec. Mineralogy variations were observed across the 10 shale samples but showed a correlation which suggests that the effective surface relaxivity is dependent on mineralogy.
Improving Gas Production and Reducing Fracture Face Damage using a Microemulsion Surfactant—Field Trail in Burgos Basin, Mexico
Authors: Lopez-Bonetti Elias , Rodriguez Levi , Coronel Hugo , Garza Domingo , Martinez-Melo Luis , Bailon Leonel
Published: October 2012

Post-production performance after hydraulic fracturing has been studied for decades. Most of the issues that arise are related to drainage area and low pore pressure after the fracture is created. The goal of hydraulic fracturing is to always try to maintain the original reservoir pressure while still providing the best geometry possible. Treatment options vary, depending on the pressure and capacity of the formation to return fluids pumped to minimize face damage.

Some tight-gas wells respond very well to new, improved fracturing techniques, and proppant-carrying fluids have been continuously modified to reduce damage in the formation. But, for some wells, such as the gas fields in the Burgos basin in North Mexico—located in the North-East area of the country and bordered with South Texas in the USA—problems still persist.

This is especially problematic in unconventional gas reservoirs, such as ultralow-permeability or tight-gas sands. When fracturing, the damage mechanism must be mitigated to help prevent fracture face damage. By reducing fracture face damage caused by the use of conventional surfactants, which absorb rapidly within the first few inches and result in fluid phase trapping, relative permeability, and wettability issues, substantially increased regained permeability can be achieved in unconventional reservoirs, with the primary purpose using surfactant-reducing surface and capillary tension.

This study discusses revised operations where a novel microemulsion (ME) surfactant was used, the fluid recovery that occurred during the cleanout process, and the hydrocarbons production a few months after the stimulation. Also, these wells were compared, as much as possible, to those that received a conventional treatment. Results demonstrate exceptional water recoveries compared with conventional ME surfactant treatments.
Developing a Predictor for Degradation of High Strength Corrodible Tripping Balls used in Multi-Zone Fracturing Treatments in Unconventional Hydrocarbon Reservoirs
Authors: Carrejo Nick , Mathur Vipul , Mazyar Oleg A. , Gaudette Sean
Published: October 2012

Multi-point hydraulic fracturing in unconventional hydrocarbon-bearing shale reservoirs has proven to greatly enhance production economics. Recent technology has allowed for as many as 40 individual fracture points. Tripping balls are a major component of these multi-point fracturing systems and are used to actuate fracturing sleeves to pinpoint fracture initiation and placement. While seated on ball seats, the tripping balls may experience pressures approaching 10,000psi. However, following a successful formation fracture, the tripping balls may hinder production. Potential problems relate to the tripping balls becoming stuck on the fracturing seats. Tripping balls remaining in the lateral can also lead to problems if wellbore re-entry is required. These production risks can lead to significantly increased costs and potential lost production. A new, high-strength corrodible material has been developed for tripping balls to alleviate potential problems in these unconventional reservoirs. This material has yielded an interventionless means of flow assurance. The mechanical properties and degradation rates of these newly engineered materials have been investigated to determine the downhole characteristics. The characterization results of these materials are discussed in an effort to develop a method for accurately predicting the timeframe in which these high-strength corrodible tripping balls fully degrade, and thus eliminate possible production risks. The testing included investigations of the degradation rates of these materials in brines, and at various temperatures. Materials were also pressure tested on multiple ball seat configurations used in the multi-zone fracturing systems1.
Analysis of Finding and Development Costs in Western Canada: Looking for Most Cost Efficient Unconventional Plays
Authors: Virine Lev , Turchin Sergey
Published: October 2012

Petroleum producers are currently engaged in significant expenditure towards exploration and development in unconventional oil and gas plays in Western Canada. Finding & Development costs are different in various plays and strategies. But where the producer should focus their resources to achieve most cost efficient production?

The paper describes methodology of analysis of Finding & Development cost. A probabilistic model was developed to quantitatively assess exploration and development expenditure, production, and reserves for various producers for different oil and gas plays. The model employs a number of key performance indicators (KPIs) such as Finding & Development costs with and without acquisitions, reserves life, reinvestment, and others.

The methodology was applied to a comprehensive study of Finding & Development expenditure in Western Canada focused mostly on unconventional oil and gas. The study included more than 80 oil and gas companies. Each company may be involved in exploration and development of many plays. The expenditure, production, and reserves were analyzed for the last 12 years. The companies were subdivided into three groups based on their production. Each company’s Finding & Development costs and other KPIs were calculated for Western Canada as a whole and for a particular strategy or play where the company was operating, as well as for CBM, tight, and shale gas.

The study found significant variance in finding and development cost in Western Canada. All companies and all strategies are ranked based on their Finding & Development costs and other KPIs. The results of the study can be applied to the comparative analysis of efficiency of the exploration and development expenditure, which in turn can help improve portfolio management and decision making processes.
Real Time Measurement of Borehole Shape and Diameter by Using Ultrasonic Caliper in Different Drilling Fluid and Wellbore Conditions for Detecting Instabilities
Authors: Elahifar Behzad , Esmaeili Abdolali , Fruhwirth Rudolf K. , Thonhauser Gerhard
Published: October 2012

Drilling programs continue to push into new and more complicated environments. As a result, accurate measurements of drilling data in real time are becoming more critical by means of minimizing the risks as well as the costs. An ultrasonic caliper sensor is a key measurement for determining the borehole diameter in MWD and LWD tools. Important is the use of ultrasonic caliper tools to offer a method for calculating borehole volumes, on the final bit run, the sensor collects data while tripping out of the hole for determining borehole size and furthermore required cement volumes. Real-time applications of ultrasonic caliper measurements also strongly support the early detection of borehole instability.

This paper describes the experiments related to the accuracy of the ultrasonic sensor measurements for estimation of the wellbore diameter. A fully automated test robot has been designed and tests have been performed in different fluids and geometrical conditions. That test robot allows emulating vertical as well as lateral movements of a sensor head in an artificial wellbore which can be run with different fluids. The results of the tests were compared and the weak points and problems of the sensor for detecting the echoes were determined. Numerical simulation of the ultrasonic measurements and comparison of the simulated results to the recorded data gives estimates about the accuracy dependency to different drilling conditions. Tests with different decentralized positions of the ultrasonic caliper tool inside the wellbore give estimates about the accuracy dependence with respect to the decentralization of the tool. Finally measurements were performed in wellbores with geometrical anomalies like washouts and squeezing formations. It is shown that such anomalies can be detected in an appropriate accuracy if circle fitting methods like the Kasa method in combination with robust error models are applied.
Pressure Transient Analyses of Short and Long Duration Well Tests in Unconventional Reservoirs
Authors: Kurtoglu Basak , Torcuk Mehmet A. , Kazemi Hossein
Published: October 2012

Horizontal wells are used in unconventional oil and gas reservoirs to increase production by creating large drainage surface areas and contact volumes. Production is further improved by applying hydraulic fracture stimulation in horizontal wells. Hydraulic fracturing increases well productivity via the large drainage surface of the fracture and by rejuvenating existing natural fractures as well as creating new fractures in the vicinity of the wellbore. The affected reservoir volume is known as the stimulated reservoir volume (SRV) which includes a complex flow network that creates different flow regimes.

We will present several short and long pressure transient tests conducted in vertical and horizontal wells, to determine critical formation properties of the low-permeability, dual-porosity Middle Bakken and Three Forks reservoirs. Pressure transient test data were obtained via permanent downhole pressure gauges. The bilinear and linear flow regimes of the pressure buildup tests are the focus of the analyses. For this, we have presented an analytical solution using numerical inverse Laplace transform as well as closed-form approximate solutions.

Flow rate transient analysis of long-duration production data were also conducted to compare with the results of the pressure transient analyses. All tests indicated that the field measured permeability is several orders of magnitude greater than permeability measured on core plugs. This indicates the presence of a network of interconnected fractures and microfractures in the stimulated near-well regions without which no significant production would result. The details of the well tests and analyses will be presented for engineering applications.
Analytical Model for History Matching and Forecasting Production in Multifrac Composite Systems
Authors: Stalgorova Ekaterina , Mattar Louis
Published: October 2012

This paper presents an analytical model for unconventional reservoirs with multiply-fractured horizontal wells. The model is an extension of the "tri-linear flow" solution, but it subdivides the reservoir into five regions instead of three. This enables it to be used for more complex reservoirs. Accordingly, the model can simulate a fracture that is surrounded by a stimulated region of limited extent (branch-fracturing), while the remaining reservoir is un-stimulated. In addition to modeling flow within the fracture and flow within the stimulated region, the model takes into account flow from the surrounding un-stimulated region, both parallel to and perpendicular to the fracture.

The model can be used to simulate the flow in tight reservoirs with multi-frac horizontal wells. In many cases, the fractures do not have a simple bi-wing shape, but are branched. This effectively creates regions of higher permeability around each fracture, which obviously affect the production performance significantly. However, in many tight reservoirs, in spite of their low permeability, the surrounding un-stimulated region can also be a significant contributor to long-term production. The Five-Region Model accounts for this contribution. Thus it is particularly valuable when generating production forecasts for reserves evaluation.

The model was validated by comparing its results against numerical simulation. We found that analytical and numerical results are in good agreement only when the geometry of the system falls within certain limitations. However these limitations are met in most cases of interest. Therefore the model is useful for practical engineering purposes.
Study of 2-D and 3-D Hydraulic Fractures with Non-Uniform Conductivity and Geometry Using Source and Sink Function Methods
Authors: Xiao Lei , Zhao Gang
Published: October 2012

During hydraulic fracturing process, different hydraulic loading and stress status of formations result in hydraulic fractures with various geometries and properties. Several propagation models including PKN and KGD have been widely applied in fracturing design and implementation. However, in the process of post-stimulation modeling, fractures are usually simplified with uniform geometries and conductivity distribution; therefore the effects of actual fracture geometry and proppant properties on the well transient pressure and production performance remain unclear. This study intends to comprehensively study the fractured wells with 2-D and 3-D non-uniform geometry and conductivity distribution.

In the development of shale gas reservoirs and tight oil formations, horizontal well multistage fracturing is the key technology. The modeling results presented in this paper can help offer valuable information of reservoir properties, evaluate the conductivity distribution of propped fractures, simulate more realistic fracture configurations, and help optimize fracture treatment process and fractured wells’ performances with improved accuracy.

A semi-analytical approach coupling fluid flow in reservoir and fractures existed in more realistic shape with non-uniform conductivity distribution has been developed to obtain well transient pressure and production responses. Source and sink function method is utilized to solve unsteady state flow problems of fluid flowing from reservoir to non-uniform fractures with geometries that are well defined in PKN, KGD and other generally ideal models. The effect of fracture conductivity with linear and stepwise distribution, and elliptic fracture shape variations has been investigated. Comparison study has been highlighted to illustrate effects of fracture geometry and conductivity distributions. Realistic hydraulic fractured wells with non-uniform fracture geometry and conductivity have been studied to showcase a consistent workflow of entering fracture properties from hydraulic fracturing models and outputting fractured well performance prediction in post-stimulation reservoirs.

Instead of assuming pseudo-steady state flow status between reservoir and fracture, unsteady state flow problems related to non-uniform fracture geometric have been solved in a semi-analytical manner with solution of near analytical accuracy. More realistic fracture geometries estimated from fracture propagation models can be entered into post-stimulation models without idealized simplification; thus the gap between fracture propagation and post-stimulation modeling has been fulfilled.
Determination of Fracture Conductivity in Tight Formations with Non-Darcy Flow Behaviour
Authors: Zhang Feng , Yang Daoyong
Published: October 2012

In this paper, a mathematical model has been developed and successfully applied to accurately determine the fracture conductivity in tight formations with non-Darcy flow behaviour. A new non-Darcy flow number is first defined to account for effect of characteristic length in a hydraulic fracture. A semi-analytical method is then applied to solve the newly formulated mathematical model by discretizing the fracture into small segments, assuming that there exists unsteady flow between the adjacent segments. The newly developed model has been validated by simplifying it to the traditional Forchheimer (i.e., non-Darcy) model. The pressure response together with its corresponding derivative type curves has been reproduced to examine non-Darcy flow behaviour under different fracture conductivities. Both relative minimum permeability and characteristic length are found to impose a negative impact on fracture conductivity. Compared to relative minimum permeability, characteristic length is a strong function dominating the non-Darcy flow behaviour in the fractures. It is obvious that the fracture conductivity can be accurately determined when non-Darcy flow behaviour in the fracture network is taken into account.
Optimization of CO2 Flooding Schemes for Unlocking Resources from Tight Oil Formations
Authors: Song Chengyao , Yang Daoyong
Published: October 2012

In this paper, techniques have been developed to experimentally and numerically evaluate performance of waterflooding and CO2 flooding for unlocking oil resources from tight formations. Experimentally, core samples collected from a tight formation with a permeability range of 0.081–0.790 mD are used to conduct a series of coreflooding experiments. The performance of four flooding schemes, i.e., waterflooding, near-miscible CO2 flooding, miscible CO2 flooding, and water-alterneating-CO2 flooding, are evaluated by the coreflooding experiments. The continuous CO2 flooding processes under either miscible or near-miscible condition lead to a superior oil recovery performance in comparison with the waterflooding process. Furthermore, the miscible water-alternating-CO2 flooding in tight cores leads to a higher recovery efficiency with less CO2 consumption compared to the continuous CO2 flooding processes. Most importantly, in the miscible water-alternating-CO2 flooding process, it is found that the pressure drop increases rapidly when water is injected, but decreases dramatically when CO2 is injected. This indicates that CO2 injection is able to significantly improve the fluid injectivity in tight formations. In general, the miscible water-alterneating-CO2 flooding process is found to be the most favorable flooding scheme for tight formations in terms of both recovery efficiency and fluid injectivity. Theoretically, numerical simulation is performed to match the experimental measurements obtained in the different flooding schemes. There exists a generally good agreement between the experimental measurements and simulated results for all the flooding schemes examined. The tuned numerical model is then employed to optimize the production pressure in the continuous CO2 flooding process and the water-alternating-gas (WAG) ratios in the miscible water-alternating-CO2 (CO2-WAG) flooding process, respectively. It is found that the optimum producing pressure in the continuous CO2 flooding process can be set as the minimum miscibility pressure (MMP) of the tight oil sample, while the optimum WAG ratio falls in the range of 4:1 to 8:1.
The Optimal Completion Techniques for Horizontal Gas Wells in the Cadomin Formation, Northeastern British Columbia
Authors: Yu Shaoyong
Published: October 2012

The Cadomin formation, consisting of conglomerates and sand systems, is an aerially extensive resource play that covers the entire area of northeastern British Columbia, Canada from Township 77, Range 21W6 to Township 68, Range 11W6 in the Elmworth area. It further extends south for hundreds of kilometers along the eastern edge of the Rocky Mountains. The gross pay thickness in the Cadomin formation ranges from 20 ~ 30 meters with porosity ranging from 2 to 7% and matrix permeability ranging from 0.006 mD to 0.7mD, based upon available in-situ Special Core Analysis data.

Due to the low estimated ultimate recovery (EUR) from a typical Cadomin vertical well, there have been more than 300 horizontal wells (including multi-lateral horizontal wells) drilled in this formation since 2001 in order to improve the ultimate recovery. Various completion techniques have been tried in those horizontal wells, which use mainly slick-water bullhead or multi-stages fracturing with or without proppant.

After a review of the public completion data for more than 200 horizontal wells, it was found that as high as two-third of the wells had used only slick-water in either bullhead or multi-stage fracturing; about one-third used slick-water with proppant sand, and the remaining few percent using some other techniques. Detailed analysis of the completion techniques, wells’ EURs and the first 3-month gas production has provided some insights into the following questions: Does fracturing work better with slick-water alone or with proppant?For those wells using slick-water during fracturing, does the amount of water used affecting the final EUR and initial production? Is it true that more water is used better the initial production and the EUR?What are the benefits of using multi-stage fracturing vs. bullhead fracturing?What is the conductivity of the fractures generated by slick-water?
Laboratory Measurement of Sorption Isotherm under Confining Stress with Pore Volume Effects
Authors: Santos Jose M. , Akkutlu I. Yucel
Published: October 2012

For unconventional gas resources such as coal and organic-rich shale, sorbed-phase is an important component of storage and transport calculations. Routine measurements of sorption are, however, performed separately from the porosity and permeability measurements. In this work a new gas storage measurement technique is proposed combining the porosity and sorption measurements. Because the measurement is done using core plug under confining stress, it allows investigating the storage capacity for varying effective stress and incorporating the storage data into a subsequent permeability measurement under the same conditions.

During construction of the sorption isotherm in the laboratory using Boyle’s law setup and a volumetric method, at each pressure step, volume of the sorbed gas taken up by the sample reduces the pore volume of the sample. As a result, the initially determined pore volume at low pressure must be corrected at the beginning and at the end of the pressure step. Also known as Gibbs correction, this correction can be done relatively easily during the routine sorption measurements with the crushed samples; however, it is a challenging task with core plugs under confining stress because at each pressure step the pore volume could also change due pore compressibility. Our approach is based on a new analytical model of total gas storability developed to interpret multiple-step laboratory measured pressure data on a graphical domain where the parameter estimation can be done fast and accurately using a straight line. The approach considers both the compressibility and sorbed- phase effects on the pore volume and the sorption parameters.

Experimental storage data of various shale and coal samples with varying total organic content and maturity is used to demonstrate applicability of the analytical method to the measurements. Our results show that the sorption measurements can be done with increased accuracy and relatively fast. The work is important for organic-rich sample characterization in the laboratory, and for gas-in-place and transport calculations.
A Case Study to Evaluate Shale Gas Performance Models with Actual Well Production Data
Authors: Yuan Hong , Bhuiyan Mofazzal , Xu Jiafu
Published: October 2012

In this study, three shale gas production models are evaluated against field data from 17 gas wells in four different shale types.

Gas production from unconventional gas reservoirs keeps growing. Although there are many models have been published in the literature, sometimes it is difficult to determine which model to use in predicting the production rate.

Based on a broad literature survey, three shale models were selected to evaluate against field data. The three models are the Duong model, the stretched exponential production decline model and the fracture flow model. The field data are from 17 gas wells in the Barnett shale, the Woodford shale, the Fayetteville shale and the Haynesville shale. Among the 17 wells, there are both dry and wet gas wells, the production history ranges from 3 to 8 years and the maximum monthly production rate ranges from15 MMcf/month to 160 MMcf/month. In the 17 wells, 14 are horizontal and 3 are vertical.

The results of this study can be used as guidelines in choosing shale gas models.
A Model of Canadian Oil and Gas Price Fluctuations - 2012 Update
Authors: Morgan Michael , Herchen L. , Mikalson D.
Published: October 2012

In 2005 a series of statistical calculations were presented for Canadian hydrocarbon prices [1]. There were two main conclusions: long-term historical data indicates that hydrocarbon prices tend to revert back to historical averages, short-term price fluctuations are unpredictable. It is more clear than ever that short-term prices are unpredictable, but this paper will attempt to demonstrate once more that mean reversion should be included in any long-term model.

This paper demonstrates that any discussion of oil and gas prices in Canada must consider inflation. Several different means of adjusting for inflation are presented but all show that Canadian hydrocarbon prices are strongly variable, but mean reverting. This paper also argues that, while convenient, discussing the price of a commodity in terms of only one currency ignores changes in the relative value between currencies and basis differentials. These factors can have significant economic impact.

This paper updates the previous price fluctuation model for prices up to the end of 2012. As before, the model incorporates a random walk with mean reversion that was developed and tuned to fit Canadian hydrocarbon prices. Starting with the current spot price, the model will generate a random but equiprobable prediction of future prices. The model can be used as input into a Monte-Carlo simulation. Alternately, the model can be run multiple times in order to generate "high", "low", and "expected" price predictions.
Water-in-Oil emulsions: Flow in Porous Media and EOR Potential
Authors: Fu Xuebing , Lane Robert H. , Mamora Daulat D.
Published: October 2012

High water content (>50%) water-in-oil (W/O) emulsions have been suggested as a drive fluid for recovery of heavy oil in high permeability reservoirs. High emulsion viscosity can provide sufficient mobility control and its oil-external nature enables a semi-miscible process while displacing crude oil. Initially crude oil itself was suggested as base oil for generating this type of emulsion, and both laboratory experiments and field pilot have demonstrated its high efficiency in recovering heavy crude. Recently used engine oil was suggested as a candidate for generating W/O emulsions for the same purpose, because of its better stability and more favorable viscosity.

In this work a stable emulsion was generated by mixing used engine oil (40%) and brine (60%) under high shear. Then this emulsion was injected into sandstone cores (400 ~ 2400 md, 0.5 or 1 ft in length) at several different rates for periods of several days, to characterize its stability and flow properties while passing through porous media. Small amounts of water breakout were observed in the emulsion effluents. Higher values of water breakout were observed in lower permeability rock, at higher injection rate, and with longer core lengths. The the emulsion was also injected into sand-packed slimtubes (~8000 md) of 3-ft and 6-ft lengths, and less than 1% of free water was observed from the effluents at moderate injection rates, verifying good stability of this emulsion passing through high-permeability porous media. Pressure drops were found to be quite stable at any constant rate of injection for all corefloods, indicating no plug-off effect from the soot particles in the emulsion.

Numerical simulations on emulsion flooding a homogeneous heavy oil reservoir were also conducted by simulating the emulsion as single-phase oil, and the breakdown of emulsion as a co-injection of water together with this oil. Results indicated significant improvement of displacement pattern and oil recovery compared to water flooding.
Importance of the Transition Period to Compound Linear Flow in Unconventional Reservoirs
Authors: Liang P. , Thompson J. M. , Mattar L.
Published: October 2012

Unconventional wells often show linear flow. Rate Transient Analysis (RTA) so far has only concentrated on the primary (early-time) linear flow. However, real production data has often shown more than one transient flow regimes. There are only few studies that focus on analyzing the flow regimes following the primary linear flow. It is not clear how to deal with the transition period as well as the compound (late-time) linear flow. When does the transition start? How long does the transition last? Does compound linear flow always exist? What are the diagnostic values of analyzing the period of transition to compound linear flow? This work answers these questions.

We developed a dimensionless typecurve for a single multi-fractured horizontal well (large inter-well spacing). We investigated the end of the primary linear flow, the duration of the transition and the start of the compound linear flow, for different fracture spacing to fracture half-length ratios. We investigated the effect of skin and superposition time functions. In the end, we proposed a workflow to analyze the production data from multiple-fractured horizontal wells by using the newly developed typecurve, and we presented a field example to show the application of the proposed methodology.