bluuebunny/crossref_metadata_2025_split huggingface dataset:
Tight Oil Production Analysis: Adaptation of Existing Rate-Transient Analysis Techniques
Authors: Clarkson C. R. , Pedersen P. K. 
Published: February 2011

Abstract
Low-permeability (tight) oil reservoirs have emerged as a significant source of oil supply in North America. Hydraulic fracturing techniques combined with horizontal well technology have enabled commercial production from oil and gas reservoirs with absolute permeability &lt; 0.1 md, and recently in gas reservoirs with permeability in the nanodarcy range. Techniques for quantitative analysis of ultra-low permeability reservoirs completed with hydraulically-fractured horizontal wells are in their infancy; complications that have slowed development of these techniques include complex reservoir behavior, such as dual porosity effects, multi-layer behavior, multi-phase flow and non-static absolute permeability, and complex flow behavior associated simultaneous flow of multiple hydraulic fractures into horizontal wells. Although analytical models have been and currently are being developed to simulate well performance associated with these complexities, systematic methods for analyzing production for the purpose of quantifying reservoir and hydraulic fracture properties have not been discussed in detail in the literature for tight oil reservoirs.
This paper examines the use of classic rate-transient techniques (flow-regime analysis, type-curve methods and simulation) for analysis of tight oil reservoirs. Single-phase (oil) flow associated with undersaturated black oil reservoirs (above bubble point) is the focus of this work. Simulated cases of multi-fractured horizontal wells completed in single porosity reservoirs, as well as naturally-completed horizontal wells in transient dual porosity reservoirs are analyzed. In all cases, the proposed integrated rate-transient analysis approach provided reasonable estimates of (simulator input) hydraulic fracture and reservoir properties. A field case of a multi-fractured horizontal well completed in a low-permeability area of the Pembina Cardium Field, Western Canada, is also given. Finally, a simplified method for forecasting horizontal wells completed in single and dual porosity media, using inputs derived from flow-regime analysis, is introduced.
Multioriented Fracturing in Unconventional Reservoirs Offers Improved Production by Better Connectivity
Authors: Surjaatmadja J. B. 
Published: February 2011

Abstract
In the oilfield, the term "unconventional" almost always means difficult to get, for one or another reason. One reason addressed in this paper relates to formations characterized by the lack of permeable features that connect or can be easily connected to the wellbore using conventional stimulation techniques. The common logic of placing larger and larger fractures does work but, when using this approach, the cost-over-reward ratio can be far from desirable.
It is well-known that placing a second fracture sometime later in the life of a well will result in a fracture that extends in a slightly different direction, mostly caused by the drainage of the fluid near the fracture face. In this situation, fracture redirection is probably caused by the pore-pressure decline near the producing fracture face. In some instances, the new fracture produces almost as if it has reached a new formation.
This paper discusses placement of such "second" (or third) hydraulic fractures within the same time domain from the same wellbore section. It is believed that the first fracture will modify the stress field to a perpendicular direction. Combined with the hypothesis of the hard-to-accept concept that fractures often shy away from the most productive areas, this approach will cause the second fracture to extend directly into the more productive areas, thus providing a substantial production boost.
Methods and Tools for the Development of Consistent Reservoir Rock Type Based Relative Permeability and Capillary Pressure Models for Reservoir Simulation
Authors: Kralik J. G. , Guice K. , Meissner J. P. 
Published: February 2011

Abstract
A workflow for generating internally consistent sets of saturation functions from capillary pressure and relative permeability data for use in numeric reservoir simulation is described. This workflow was implemented in software that was developed to facilitate the filtering and grouping of these data using a variety of screening criteria. Such implementation ensures the application of consistent practices, based on the physics of multiphase displacement in porous media, when developing relative permeability and capillary pressure models. The data are reviewed to confirm that they are of acceptable quality prior to use in saturation function development. The workflow described here conforms to the displacement categories defined in the simulation model, e.g. families of reservoir facies. In addition to grouping and analyzing SCAL data (capillary pressure, relative permeability, wettability) for a specific reservoir, the software can access a larger database that contains all available SCAL data. The database also provides convenient access to analog data for reservoirs in which sufficient SCAL data have not been generated. To our knowledge, such a systematic method for the development of consistent capillary pressure and relative permeability saturation functions based on families of reservoir facies for simulation has not been presented in the literature.
Saturation endpoints are first established by analyzing the appropriate capillary pressure data (e.g., primary drainage Pc for Swir, primary imbibition water-oil Pc for Sorw, primary drainage gas-oil Pc for Sorg, etc.). This analysis involves fitting the data to a consistent constitutive equation that contains the saturation endpoint as a regression parameter. The resulting models should be compared to any available field data to ensure consistency (e.g., primary drainage Pc vs. calibrated log Sw(z)). Once the saturation endpoints have been established, the grouped relative permeability data are analyzed, starting with the bounding water-oil primary drainage data. After defining the bounding primary drainage curves, the primary imbibition krow-krw curves can be developed. Individual imbibition krow-krw tests generally correspond to unique imbibition scanning curves rather than the bounding primary imbibition curve, suggesting the measured imbibition curves be scaled to the bounding primary drainage kro curve to ensure consistency. Secondary drainage kro-krwo data, if available, are similarly scaled. Three-phase gas-oil primary drainage krog-krg and primary imbibition kro-krgo data are treated in an analogous manner. This process is applied to each group of capillary pressure and relative permeability data. Experience has shown that this approach properly represents the displacement physics, facilitating accurate reservoir performance predicitions and history matches.
Flaws in Fracture Designs: A Continuing Problem
Authors: Marongiu-Porcu M. , Liu W. , Economides M. J. 
Published: February 2011

Abstract
Although hydraulic fracturing has become the second largest outlay of petroleum companies after drilling, design and execution issues are still heavily contaminated by lingering misconceptions and inadequate empirical "rules-of-thumb". Some of the most common problems include issues such as "maximizing" fracture conductivity or fracture length (sometime referred to as "effective" or "apparent"), or even more inadequate goals during execution such as cutting costs by shortening the injection time and using the cheapest possible proppants.
Since the introduction of the Unified Fracture Design (UFD) approach, practitioners have a coherent method to design fracturing treatments aiming to maximize the post-treatment productivity index. The central idea of the UFD technique is to select an optimum compromise between propped fracture length and width, for a given proppant volume and depending on the properties of the reservoir and the selected proppant.
We present in this paper a wide range of parametric studies for oil and gas reservoirs with permeability ranging from 0.01 md to 500 md, and we assess the impact of treatment size (mass of proppant injected) and proppant pack permeability, starting from the UFD-determined optimum designs and then departing towards suboptimal conditions. These include fracture length, the fracture conductivity and fracture height (by using the concept of fracture aspect ratio). We also apply the same approach to study gas wells, in which turbulence effects in moderate to high permeability reservoirs require the adjustment of optimum design geometry. Finally, we show how a proper candidate selection among a given portfolio for hydraulic fracturing treatments can easily provide a much higher incremental production from a much smaller number of treatments. We use both vertical and horizontal well fracturing.
Our results show clearly that there is a lot of room for improvement in fracture designs for production enhancement, particularly dealing with larger treatments and the selection of better quality proppants (higher pack permeability), especially for gas wells. This leads to a systematic approach for design and a studious departure from optimum design conditions, when necessary, based on field constraints and reservoir and fluid characteristics.
Relative Permeability of CBM Reservoirs: Controls on Curve Shape
Authors: Clarkson C. R. , Rahmanian M. R. , Kantzas A. , Morad K. 
Published: February 2011

Abstract
Relative permeability to gas and water for 2-phase flow coalbed methane (CBM) reservoirs has long been known to exhibit a strong control on (gas and water) production profile characteristics. Despite its important control on both primary and enhanced recovery of CBM for coal seams that have not been fully dewatered, relative permeability in coal has received little attention in the literature in the past decade. There are few published laboratory-derived curves; these studies and their resulting data represent a small subset of the commercial CBM reservoirs and do not allow for a systematic investigation of the physical controls on relative permeability curve shape. Other methods for estimation of relative permeability curves include derivation from simulation history-matching, and production data analysis. Both of these methods will yield pseudo relative permeability curves whose shapes could be affected by several dynamic CBM reservoir and operating characteristics.
The purpose of the current work is to perform a systematic investigation of the controls on CBM relative permeability curve shape, including non-static fracture permeability and porosity, multi-layer effects and transient flow. To derive the relative permeability curves, effective permeability to gas and water are obtained from flow equations using a modified version of the approach described by Clarkson et al. (2007). Simulated cases are analyzed so that derived and input curves may be compared allowing for investigation of CBM reservoir properties on curve-shape. One set of relative permeability curves that were input into the simulator were derived from pore-scale modeling. Field cases from two basins are also examined and controls on derived relative permeability curve shape inferred. The results of this work should be useful for future CBM development and greenhouse gas sequestration studies, and it is hoped that it will spark additional research of this critical CBM flow property.
Evaluating Unconventional Reservoirs: The Questions We Need to Answer
Authors: Russum D. A. 
Published: February 2011

Abstract
North America has embraced unconventional gas reservoirs as the solution to declining conventional production, and today virtually every E&P company has some unconventional gas reserves or resources in their portfolio. As North America demonstrates success in our unconventional reservoirs, interest in unconventional opportunities is spreading to basins throughout the world.
However, as unconventional opportunities grow and develop, the consistent evaluation of unconventional resources and reserves is becoming a major issue for our industry. The newness of many unconventional plays means historical trends are limited. In addition, no two unconventional plays are the same and variations within a play can yield substantially different results.
Evaluators and their clients need to consider many issues in order to determine the real value of an unconventional opportunity. Early and regular discussion between clients and their independent evaluators ensures that the right questions are being asked and those questions are answered as efficiently as possible. While it is important that evaluators provide an independent opinion of resources and reserves, this opinion is weaker when it fails to take into account all the relevant information possessed by the client.
Mapping Key Reservoir Properties Along Horizontal Shale Gas Wells
Authors: Khalid S. , Faurschou K. , Gorchynski T. , Zhao X. , Marechal F. C. 
Published: February 2011

Abstract
Heterogeneity of properties along horizontal shale gas wells has a significant impact on the quality of completion as well as on production from each stage. This heterogeneity can exist in the quality of the reservoir, such as changes in kerogen content and maturity, free porosity, and water saturation, and it can also be seen in factors which directly affect the course of induced fracturing in the well. These factors can be faults, natural fractures, stress regime changes, etc.
Historically, it has been difficult to map these properties because some of the measurements required logging in openhole environments using wireline tools. Recently, logging-while-drilling and through-casing-logging measurement techniques have been developed to achieve similar results in a safer, more controlled environment.
A large number of horizontal wells have been drilled in gas shales in the USA and Canada. Some of these wells have been logged in an attempt to understand variability. The authors have studied these data sets in detail, and the concepts presented here are based on observations from these data sets. We use a data set acquired in a Canadian shale as an example to illustrate the concepts of property heterogeneity along the laterals. This well is a 1,000-m long lateral which was supposedly drilled in the same, homogeneous rock, yet it shows substantial property differences along its length, suggesting the importance of evaluating horizontal wells.
Once these properties have been mapped, many questions can be raised. Can we increase production from the same horizontal well, which has already been drilled (Potapenki et al SPE 119636; Ketter et al SPE 103232) ? Can we do something better in planning the completion to get more gas out of it? Would it be possible to save a well from geohazards if we knew how we might connect to them? Can we select the optimum perforation interval when we know the quality of cement behind pipe? The answer to each of these questions can result in substantial gains in efficiency and reduction in risk, while providing major production boosts. To determine definitive answers to these questions, production data over time would need to be analyzed. These data were not available at the time of writing this paper; hence, a detailed discussion on the specifics of the correlations between properties and production is left for another paper.
Analyzing Production Data From Tight-Oil Wells
Authors: Kabir C. S. , Rasdi F. , Igboalisi B. 
Published: February 2011

Abstract
Performance prediction of wells producing from tight microdarcy formations is a daunting task. Complexities of geology (the presence/absence of naturally occurring fractures and contribution from different lithological layers), completion and fracture geometry complexities (multiple transverse and/or longitudinal fractures in long horizontal boreholes), and two-phase flow are impediments to simple performance forecasting.
We demonstrate the use of various analytical and numerical tools to learn about both short- and long-term reservoir behaviors. These tools include (a) traditional decline-curve analysis (Arps formulation), (b) Valko's stretched-exponential method, (c) Ilk et al's power-law exponential method, (d) rate-transient and transient-PI analyses to ascertain the stimulated- reservoir volume, and (e) numerical simulation studies to gain insights into observed flow regimes.
The benefits of collective use of analytical modeling tools in history-matching and forecasting both short- and long-term production performance of tight-oil reservoirs are demonstrated with the use of real and simulated data. Diagnosing natural fractures, quantifying stimulated-reservoir volume, and assessing reliability of future performance predictions, all became feasible by using an ensemble of analytical tools.
Fully-Coupled Wellbore Design and Optimization for Thermal Operations
Authors: Kumar A. , Oballa V. , Card C. C. 
Published: February 2011

Abstract
Steam Assisted Gravity Drainage (SAGD) is a widely used enhanced oil recovery process applied in Canadian oil sands projects. Operators of SAGD projects have long been aware that many factors such as near wellbore geology, tubular sizes, lengths, and the allocation of fluid rates between tubulars in multi-string completions, can significantly impact the effectiveness of well and well- pair operations. The interaction of well components within these complex wells and the reservoir can impact the economic and technical success of the entire project either positively or negatively, suggesting that a means of optimizing this interaction that couples wellbore effects with the reservoir is required. Simulation studies were carried out to investigate the impact of wellbore design optimization on the well's performance. Reservoir simulation was used as a tool to evaluate the advantages derived from the optimization of wellbore and tubular design for thermal projects using a new fully coupled reservoir-wellbore modeling approach linked to an optimization algorithm.
This paper presents results that cover important aspects such as the impact of geological heterogeneity on wellbore design; the optimization of length and positioning of multiple tubular strings within a liner for both injection and production wells; and the optimization of the allocation of injected steam between multiple tubing strings. The results indicate positioning of tubulars in a multiple tubing completion SAGD well pair have a significant impact on the steam chamber growth, productivity, SOR and ultimately on NPV. This paper presents results of two optimization cases. The base case wellbore completion had two tubing strings, the short tubing string was landed at the heel while the long tubing string was landed at the toe of the horizontal SAGD well pair. First optimization was performed by changing the length/placement of tubing strings in the injector and the producer. Optimization of tubing placement increased the NPV of the well pair from 16.3 M$ to 20.7 M$ over 8 years. The Second optimization study was performed including the tubing placement similar to the previous case along with the SAGD operating strategy in terms of steam injection rate that was allowed to change every two years. In this case the NPV was optimized from 16.3 M$ to 25.79 M$ over 8 yrs.
Reducing Exploration and Appraisal Risk in Low-Permeability Reservoirs Using Microseismic Fracture Mapping
Authors: Cipolla C. , Mack M. 
Published: February 2011

Abstract
Low-permeability reservoirs have been actively developed and considered economically viable for more than 30 years in North America, but their development has been limited elsewhere. In North America, significant infrastructure is already in place and drilling and completion costs are relatively low. The typical exploration and appraisal approach is to drill a relatively large number of low cost wells to assess economic viability. Outside North America, however, infrastructure is less developed, and costs are often higher. To achieve economical development in these areas, operators must assess resource viability by drilling as few wells as possible. The many-wells model has made international operators reluctant to explore low-permeability reservoirs in some areas. However, there is increasing interest in developing the vast resources held in tight gas, coalbed methane, and gas shale plays outside North America.
The exploration and appraisal of low-permeability reservoirs or unconventional plays is significantly different than conventional reservoirs; exploration is more like appraisal, requiring pilot programs to test commerciality of these resource plays prior to embarking upon large-scale development (Hall 2007; Stabell 2007), including the effect of completion and stimulation optimization (Haskett and Brown 2005). One essential component of low-permeability reservoir development is hydraulic fracturing, which virtually all of these wells require. With the introduction of hydraulic fracture monitoring (HFM), we are now able to measure fracture geometry and complexity, which has led to major improvements in treatment designs, well completions, and field development strategies in North America. HFM applications were once focused on development and infill drilling, but they have recently shown significant value for exploration plays (primarily in gas shale). HFM measurements now allow operators to more efficiently evaluate the effectiveness of stimulation treatments and completion approaches in exploration and appraisal wells, reducing the number of wells required to assess the economic viability of low-permeability reservoirs.
The application of HFM to exploration and appraisal programs outside North America could significantly accelerate the evaluation of low-permeability reservoirs, where selecting the appropriate hydraulic fracturing design and well completion strategy will be key to success. It could also accelerate the learning curve, which is essential to quickly reducing costs.