bluuebunny/crossref_metadata_2025_split huggingface dataset:
Characterizing and Simulating the Non-Stationariness and Non-Linearity in Unconventional Oil Reservoirs: Bakken Application
Authors: Chu L. , Ye P. , Harmawan I. , Du L. , Shepard L. 
Published: October 2012

Abstract
This paper presents an innovative integrated methodology and working procedure for characterizing and simulating the strong non-linearity and non-stationariness caused by changes in confined pressure-volume temperature (PVT) properties over time related to pore-throat size, the pressure-dependent permeability, and the intervened multiple porous media created by multi-stage fracture stimulation. The complicated physics behind the observed phenomena are explored. More specifically, this paper demonstrates and discusses the following: 1) a new rate-transient analysis (RTA) procedure to infer the stimulated reservoir volume (SRV) and fracture parameters; 2) the impact of the non-stationary feature, compaction effect, and pore-throat related PVT properties on the flow regime and well performance; 3) how to incorporate the non-stationary and non-linear features into the reservoir model; 4) the integrated procedure for history matching, performance forecast, and recovery assessment; 5) several field examples in the Bakken to illustrate the procedure.
The proposed procedure has been successfully applied for the following: 1) constructing the non-stationary, non-equilibrium, and highly non-linear simulation models; 2) facilitating the history matching by addressing permeability reduction and PVT property variations caused by compaction and capillary pressure; 3) and ensuring more reliable performance forecasts and recovery assessments.
The study shows that the reduction of the bubblepoint pressure could be several hundred psi in the typical Bakken rock; moreover, such reduction continues following the depletion via the compaction effect. The compaction effect could impair the matrix permeability by up to one order of magnitude.
The study reveals the following: 1) the confined PVT properties could widen the favored operation window, whereas the compaction effect could significantly impair the ultimate recovery of the wells; 2) the RTA-inferred SRV-related parameters are the key input for capturing the non-stationary features; 3) the impact on recovery could be over 50% without addressing the aforementioned non-stationary and non-linear issues.
This paper explores several unique phenomena in unconventional oil reservoirs which have not previously been published. The proposed analysis and assessment procedure greatly enhances the understanding of the unconventional assets and we feel will improve the accuracy of long-term rate and recovery forecasts.
Impact of Porous Media on Saturation Pressures of Gas and Oil in Tight Reservoirs
Authors: Pang Jianyuan , Zuo Julian Y. , Zhang Dan , Du Liangui 
Published: October 2012

Abstract
The tremendous efforts have been made by the industry in tapping the recoverable resources from the unconventional reservoirs in the past ten years. Shale (tight) gas and shale (tight) oil are the two typical ones. Some research studies focused on the effect of porous media on the dew point of gas condensates in terms of experimental and theoretical work. The contradictory conclusions were reached. On the other hand, some conclusions were made for crude oil as well on the basis of the measurements of the bubble point pressure of crude oil in porous media. Therefore, it is of great importance to develop an effective method to predict the phase behavior of shale gas and shale oil in porous media and investigate the effects of some factors on the saturation pressures of gas condensate and crude oil in tight reservoirs.
In this paper, a general framework of theoretical models has been developed to predict the saturation pressures of shale gas and shale oil in tight reservoirs. The Laplace equation is used to relate to the pressures in vapor and liquid phases from the curved interface. The Parachor model is applied to determine the interfacial tensions of crude oil and gas condensate. By taking into account of porous media in the proposed models, the calculations have been performed in some case studies. The effect tendency of some properties of porous media such as permeability and porosity on the dew or bubble point of reservoir fluid is discussed in this paper.
Analysis of Flow and the Presence of Fractures and Hot Streaks in Waterflood Field Cases
Authors: Baker Richard , Stephenson Tim , Lok Crystal , Radovic Predrag , Jobling Robert , McBurney Cameron 
Published: October 2012

Abstract
Over a thousand well pairs in five different fields in Western Canada have been examined using communication analysis techniques. The results of this analysis strongly suggest that in addition to conventional Darcy type flow through the matrix rock, there is also strong communication between wells through induced fractures, and/or natural fractures.
Most of these five fields are not typically thought of as naturally fractured. Nonetheless this type of fracture flow exists. It is highly likely that these hot streaks are pressure sensitive and therefore have a geo-mechanical component that controls permeability. The geo-mechanical component means that permeability can vary with time and injection pressure. This work on the Western Canadian Sedimentary Basin (WCSB) is similar to work done by Heffer in the North Sea.
2D-NMR Applications in Unconventional Reservoirs
Authors: Cao Minh C. , Crary S. , Zielinski L. , Liu C. B. , Jones S. , Jacobsen S. 
Published: October 2012

Abstract
In conventional reservoirs, 2D-NMR fluids evaluation targets the free fluid part of the total porosity with the assumption that the bound fluid is irreducible water. As such, pulse sequences are designed for long relaxing fluids, and the interpretation commonly assumes free diffusion of hydrocarbon molecules in water-wet pores. This is clearly not appropriate for unconventional reservoirs such as shale gas and shale oil where the fast-relaxing fluids of interest reside in the bound fluid region.
We show a revised 2D-NMR model that focus on fast relaxing fluids. In unconventionals, the three causes of fast relaxation are: small pore size, heavy oils and wettability alteration. The fast relaxation has the following consequences with respect to diffusion. In small pores, fluids cannot diffuse freely, and hence, the free diffusion lines of water, gas and oil must be corrected accordingly. In heavy oils, the oil relaxation can be enhanced by a wettability change to an oil/mixed-wet system. Another case of hydrocarbon-wet systems is hydrophobic kerogen. Consequently, the oil diffusion line as a function of viscosity (T2) must also be modified before the 2D map interpretation. This can be accomplished within the framework of the restricted diffusion model previously applied to water and gas that captures both the effects of surface relaxation and geometric restriction to molecular motion.
The results of the revised 2D-NMR model are shown through modeling and log examples in a shale gas reservoir and a shale oil reservoir. In real rocks, there is also a need to take into account simultaneously two models: an unconventional model as described above and a conventional model for long relaxing fluids associated with the matrix of the rock. The 2D-NMR log results are compared with lab results. Essentially, we show that adding diffusion and T1 information to standard T2 relaxation logs improves both the understanding and evaluation of unconventional reservoirs.
On the Fracture Height Migration Under Unified Fracture Design Optimization
Authors: Yang Mei , Valkó Peter P. , Economides Michael J. 
Published: October 2012

Abstract
We have published already a three-layer p-3D fracture design optimization using the Unified Fracture Design (UFD) approach; fracture height, resulting from fracture geometry optimization and therefore net pressure, was matched against the value resulting from fracture height migration at the same pressure.
For a multi-layered formation a more robust and more general approach is suggested in this work. First a range of admissible reference treating pressures is prepared. For each pressure level we determine the up-down tip locations and hence we obtain the fracture height map. Thus, there is a relationship between induced height and net pressure and this relationship can be calculated from Linear Elastic Fracture mechanics before the actual design optimization is carried out.
According to the applicable fracture propagation model, for a given fracture half length, there exists a width and henceforth a net pressure. The ancillary height is a geometric byproduct. Matching the net pressure and height with the LEFM independently determined pair of height and net pressure results in a solution that satisfies both. The dimensionless productivity index, JD, is then calculated.
For the fracture half lengths, ranging from a minimum (corresponding to aspect ratio one with respect to the perforated thickness) to a laterally fully penetrating fracture, we repeat the above procedure to calculate JD and so forth, until a maximum JD is accomplished.
NPV-Based Design for Coal Seam Reservoirs
Authors: Jukes Rachael , McIntosh Carl , Amorer Gabriel , Economides Michael J. 
Published: October 2012

Abstract
The production of natural gas from coal seam gas reservoirs has had a long and established history in the energy industry. Due to the relatively low permeability seen in many of these reservoirs, hydraulic fracturing is sometimes required to achieve economic production rates. The economic validity of hydraulic fracturing is dependent on a number of factors, including reservoir properties (and subsequent production rates), cost of stimulation services, as well as the type and quantity of materials. The justification of hydraulic fracturing is usually performed through net present value (NPV) analysis. NPV models for hydraulic fracturing in conventional and shale reservoirs are readily available in literature; however the same cannot be said for coal seam gas.
This paper presents a NPV model adjusted to the coal seam gas environment. That is, it considers the effect of the dewatering period required before natural gas may be desorbed from the targeted formation. The model only considers the incremental production of hydraulic fracturing as well as the incremental cost to fracture, thereby demonstrating the true present value of the treatment. Included in the model is a break-even price required for sales gas.
The production data represented within this paper was forecasted utilizing a pseudo three dimensional model that integrates unified fracture design (UFD). Sensitivity analyses were performed based on variances in reservoir properties (e.g. net pay, permeability, Langmuir isotherm) and stimulation design (e.g. proppant mass, type of proppant). This allows for greater understanding of the effects of the reservoir upon the economics of the project, as well as providing a means to economically optimize stimulation design.
Pore Pressure Modeling and Stress Faulting Regime Determination of the Montney Shale in the Western Canada Sedimentary Basin
Authors: Contreras Oscar , Hareland Geir , Aguilera Roberto 
Published: October 2012

Abstract
This work establishes an effective approach to predict pore pressure in the overpressured Montney Shale and overburden from sonic logs by implementing normal-trend and explicit methods. The cause of the overpressure condition in the Montney is also addressed. These two methods were selected on the basis of the study carried out by Contreras et al. (2011) that worked successfully for pore pressure prediction under subpressured conditions in parts of the Western Canada Sedimentary Basin (WCSB). As a second objective, the stress faulting regime was determined in the study area by using Stress Polygons and data from diagnostic fracture injection test analysis as a quantification of the minimum horizontal stress. This is of paramount importance since there is not a generic theory about the stress faulting regime for most of the west region of the WCSB.
The Eaton method from sonic logs (Eaton, 1975) and the Bowers method (Bowers, 1995) were implemented in two vertical wells drilled through the Montney shale. The first part of the analysis considered two normal compaction trends but unreasonable pressure profiles were obtained and required a revision on the depositional environment. It was found that for the study area three normal compactions trends have to be considered. The Bowers method was initially implemented using both loading and unloading conditions in order to establish a safe range of pore pressure to allow successful well plans.
It is concluded that undercompaction could be masked as the only overpressure mechanism in the Montney shale in the study area. The formation experiences an inverse faulting regime that will lead to the creation of horizontal hydraulic fractures. The Eaton method using three normal compaction trends and an exponent equal to 0.9 works successfully in the study area. The Bowers method using the loading and the unloading conditions, and the specific correlation parameters were found to be suitable for the study area and can be extrapolated to adjacent future production and exploratory wells.
Water Distribution in the Montney Tight Gas Play of the Western Canadian Sedimentary Basin: Significance for Resource Evaluation
Authors: Wood J. M. 
Published: October 2012

Abstract
Water distribution in unconventional gas reservoirs is a key parameter that influences many aspects of resource exploitation including selecting geographic areas for multi-well development programs, identifying target zones for horizontal wells, calculating reserves, estimating permeability, and understanding variability in gas and water production. Insights on water distribution in the Montney tight gas play of northeast British Columbia and northwest Alberta were gained by integrating reliable bulk volume water measurements from full-diameter core samples with other core, well log and geologic data. Water distribution in the studied Montney section was found to be related to stratigraphic architecture and rock fabric (defined by degree of bioturbation), and is interpreted to have been influenced by displacement efficiency of mobile formation water updip through tight Montney siltstones during hydrocarbon charging. Low gradient clinoform units with few shaly zones in the Lower Montney section enabled efficient water displacement and led to water contents close to irreducible water saturation. Higher gradient clinoform units with common shaly zones in the Upper Montney allowed less efficient water displacement, and significant volumes of mobile water were retained in parts of the section. Water saturation varies widely and directly influences effective gas permeability. A simple method for determining effective gas permeability from well logs was developed based on empirical relationships derived from the core and log data set. Effective gas permeability logs generated by this method help with the identification of target zones with superior reservoir quality for exploitation using horizontal multi-frac technology. A Pickett plot with effective gas permeability lines was found to be a useful tool for log-based comparison of Montney rock quality by stratigraphic zone or geographic area. This work shows that understanding water distribution and its influence on effective gas permeability leads to improved delineation of "sweet spots" for resource development in unconventional gas plays.
Understanding Anomalous Phase Behavior in Unconventional Oil Reservoirs
Authors: Du Liangui , Chu Lifu 
Published: October 2012

Abstract
Normal pressure/volume/temperature (PVT) analysis is based on a fundamental assumption that there is no potential difference between the gas a d liquid phases. The nanometer pore throats in unconventional reservoirs could impose a phase capillary pressure up to 1,000 psi. Therefore, the observed oil viscosity and bubble point pressure (Pb) in an unconventional oil reservoir are substantially lower than those reported by the PVT lab. Such reductions are further aggravated by the compaction effect and then become variable with pressure depletion. In this work, a set of non-linear fugacity equations was constructed by bringing capillary pressure in with the phase equilibrium equations.
The corresponding PVT reports for 14 Bakken fluid samples were recalibrated by combining the newly developed non- linear fugacity equations and the pore throat reduction imposed by compaction effects. The resultant PVT tables help clarify all the inconsistent PVT observations. Examples are presented to demonstrate the significance of such PVT corrections.
The corrected PVT tables were used in the Bakken reservoir simulation model and successfully resolved not only the inconsistent gas/oil ratio (GOR) issue between the model and real production data, but also substantially facilitated the history match and widened the optimal operational pressure window.
A series of studies were completed to address the combined impact of the capillary pressure and compaction on Bakken reservoir fluid properties. The Pb could be reduced in a range from hundreds to over 1,000 psi, compared to the corresponding lab PVT report. Such reduction is more severe in the lower formation permeability and solution GOR scenarios. Furthermore, oil density and viscosity could also be reduced by up to 10% due to the lighter components migrating to the oil phase. This study reveals the cause of the delayed GOR increase and the strange stepwise GOR increases observed in unconventional oil reservoirs.
This new understanding of the PVT property variation in an unconventional oil reservoir optimizes the operations procedure and will permit more reliable performance forecasts.
A Complete Petrophysical Evaluation Method for Tight Formations from Only Drill Cuttings in the Absence of Well Logs
Authors: Ortega Camilo , Aguilera Roberto 
Published: October 2012

Abstract
The amount of tight formations petrophysical work conducted at present in horizontal wells and the examples available in the literature are limited to only those wells that have complete data sets. This is very important. But the reality is that in the vast majority of horizontal wells the data required for detailed analyses are quite scarce.
To try to alleviate this problem, a new method is presented for complete petrophysical evaluation based on information that can be extracted from drill cuttings in the absence of well logs. The cuttings data include porosity and permeability. The gamma ray (GR) and any other logs, if available, can help support the interpretation. However, the methodology is built strictly on data extracted from cuttings and can be used for horizontal, slanted and vertical wells. The method is illustrated with the use of a tight gas formation in the Deep Basin of the Western Canada Sedimentary Basin (WCSB). However, it also has direct application in the case of liquids.
The method is shown to be a powerful petrophysical tool as it allows quantitative evaluation of water saturation, pore throat aperture, capillary pressure, flow units, porosity (or cementation) exponent m, true formation resistivity, distance to a water table (if present), and to distinguish the contributions from viscous and diffusion-like flow in tight gas formations. The method further allows the construction of Pickett plots without previous availability of well logs. The method assumes the existence of intervals at irreducible water saturation, which is the case of many tight formations currently under exploitation.
It is concluded that drill cuttings are a powerful direct source of information that allows complete and practical evaluation of tight reservoirs where well logs are scarce. The uniqueness and practicality of this quantitative procedure is that it starts from only laboratory analysis of drill cuttings, something that has not been done in the past.
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

Abstract
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

Abstract
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.