bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Novel Model for Fracture Acidizing with Important Thermal Effects
Authors: Lyons John , Nasrabadi Hadi , Nasr-El-Din Hisham 
Published: November 2013

Abstract
Fracture acidizing is a well stimulation technique used to improve the productivity of low-permeability reservoirs. The reaction of injected acid with the rock matrix forms dissolution channels (that depend on injection rate, mass transport properties, formation mineralogy, reaction chemistry of the acid, and temperature) through which oil and gas can then flow upon production.
The use of a model that can effectively describe fracture acidizing is an essential step in designing an efficient and economical treatment. Several studies have been conducted on modeling fracture acidizing, however, most of these studies have not accounted for the effect of variation in acid temperature (by heat exchange with the formation and the heat generated by acid reaction with the rock) on reaction rate and mass transfer of acid inside the fracture.
In this study, a new fracture acidizing model is presented that uses the lattice Boltzmann method for fluid transport and takes into account these temperature effects. The lattice Boltzmann method incorporates both accurate hydrodynamics and reaction kinetics at the solid-liquid interface. This method is also well known for its capability to handle reactive transport in complex geometries. This enables the method to model realistic fracture shapes, on a pore-scale level, and predict the shape of the fracture after acidizing. Results of carbonate fracture dissolution with and without the thermal effects are presented. It is found that including thermal effects alters the predicted shape of the fracture after acidizing.
Multi_Well Gas Reservoirs Production Data Analysis
Authors: Sureshjani M. Heidari , Behmanesh H. , Clarkson C. R. 
Published: November 2013

Abstract
Production analysis models are normally developed with the assumption of fixed drainage boundaries. However, this assumption is not always applicable. Examples where drainage areas may vary include: drilling of infill wells; shut-in of non-economic wells, and severe rate changes in some wells in the field. In such conditions, drainage volume of each well may not remain constant as time elapses.
A solution to this problem is simultaneous production analysis of all active wells in the reservoir to estimate total field gas-in- place instead of gas-in-place affected by individual wells. Such analysis requires a new boundary-dominated flow equation (BDFE) that forms a basis for analysis of field production data. In this study, a total normalized pseudopressure is defined. We show that a plot of total normalized pseudopressure versus real time forms a straight line with the slope equal to the reciprocal of total gas-in-place multiplied by initial gas compressibility. We further propose use of a new material balance time, referred to as total material balance pseudotime. We illustrate that a plot of single-well normalized pseudopressure versus this material balance time would result in a straight line with same slope. These plotting techniques account for conditions such as drilling new wells, closing damaged wells, and variations in well rate/pressure data. The introduced BDFEs are validated using several synthetic examples.
Two simulation cases are used to test the suggested techniques. In the first example, 4 wells are simultaneously producing with variable and different rates and in the second example, a new well is put on production in the reservoir every few months to simulate an infill program. In this example, 9 wells are drilled over a 6 year period. In another example, real field production data but with arbitrary reservoir systems also were used. These examples reveal the ability of the introduced techniques for estimating field gas-in-place and average pressure in multi-well gas systems. The method is very simple and can be extended to other unconventional reservoirs such as coalbed methane reservoirs and also reservoirs under two phase flow.
Production Data Analysis of Liquid Rich Shale Gas Condensate Reservoirs
Authors: Behmanesh H. , Hamdi H. , Clarkson C. R 
Published: November 2013

Abstract
With the current focus on liquids-rich shale plays (LRS) in North America and the importance of gas condensate reservoirs globally, there is an increased need to develop reservoir engineering methods to analyze such reservoirs. Commercialization of LRS plays is now possible due to new technology, such as multi-fractured horizontal wells (MFHW). Efficient production from such reservoirs necessitates understanding of flow mechanisms, reservoir properties and the controlling rock and fluid parameters. Production-decline analysis is a robust technique for analysis of production data and obtaining estimates of recoverable reserves. Nevertheless, these techniques, developed for conventional reservoirs, are not appropriate for ultra-low permeability reservoirs. There are substantial differences in reservoir performance characteristics between conventional and ultra-low permeability reservoirs. LRS reservoirs produce much leaner wellstreams compared to conventional reservoirs due to very low permeabilities that result in very large drawdowns. Methods for analysis of two-phase flow in conventional reservoirs, with underlying simplifying assumptions, are no longer applicable.
This paper discusses production data analysis of constant flowing bottomhole pressure (FBHP) wells producing from LRS (gas condensate) reservoirs. A theoretical basis is developed for a gas condensate reservoir during the transient linear flow (drawdown) period. The governing flow equation is linearized using appropriately defined two-phase pseudopressure and pseudotime functions so that solutions valid for liquids can be applied. The derived backward model is employed to compute the linear flow parameter, xf√k.
Simulation results show that the liquid yield will be approximately constant for LRS wells during the transient linear flow, from the early days of initial testing, if flowing BHP is almost constant. An analytical formulation is used to prove this finding for 1D transient linear flow of LRS wells.
The proposed production data analysis (PDA) method is illustrated using simulated production data for different fluid models and relative permeability curves. Fine-grid compositional and black oil numerical models are used to this purpose.
Hydraulic Fractures Interference in Horizontal Wells: Compact and Diffuse Patterns of Fracture Growth
Authors: Geilikman Mikhail , Wong Sau-Wai 
Published: November 2013

Abstract
Multiple hydraulic fractures interference due to induced stress is considered in the framework of approximate analytical model. The induced stress structure is generalized for the case of fractures of arbitrary length and height which allows to describe stress evolution in the process of fracture growth. Two main regimes of hydraulic fracture growth are considered: isotropic (circular) growth and limited-height (Perkins-Kern-Nordgren) regime. Major control parameters for each of them have been found, capturing dependence on pumping rate, spacing and cumulative injected volume as well as mechanical properties of the reservoir. For isotropic growth the fracture interference can be avoided by sufficiently low pumping rate and /or sufficiently large spacing whereas for limited-height growth certain limitation of total volume of pumped fluid is needed. The concept of "compact" and "diffuse" pattern of hydraulic fracturing is introduced which corresponds to weak and strong fracture interference respectively. The identified control parameters provide recommendation for optimal hydraulic fracturing design.
Optimized Production in the Bakken Shale: South Antelope Case Study
Authors: West David R.M. , Harkrider John , Besler Monte R. , Barham Michael , Mahrer Kenneth D 
Published: November 2013

Abstract
Focused modifications in drilling, reservoir, and completion engineering from 2009 to the present have improved Bakken, specifically the South Antelope Field, production as much as 50% to 75%. To achieve these results, Helis Oil and Gas Co., LLC formed a multi-disciplinary team in 2008 which it tasked with evaluating and overhauling its completion approach. Pre- 2008 completions followed conventional wisdom: target the Middle Bakken Formation between the Lodge Pole and the Three Forks Formations. Pre-2009 wellbore constructions included "kick outs" (i.e., multi-lateral), open-hole completions; short laterals; single-stage ported subs; sliding sleeves; and long stage intervals and were erratic and inconsistent. The designs and procedures resulted in a high percentage of pre-mature screenouts. In addition, the production responses on these Middle Bakken completions averaged 330 bopd with an estimated ultimate recovery (EUR) of 300 MBOe. During the pre-2009 period, 3 Three Forks were completed and these wells produced on average 550 bopd. After evaluating the pre-2009 results, the team recommended 10 changes: (1) change landing target to the Three Forks; (2) increase lateral lengths ~2x from "640’s" to "1280’s"); (3) increase formation contact (completion method, stage lateral length and, perforation spacing/density); (4) refine pump-down operations; (5) implement critical fracturing mechanisms diagnosis; (6) incorporate proppant selection (ceramic versus sand); (7) refine flush procedure to include monitoring and assure consistency; (8) integrate on-site, real-time pressure management and proppant schedule including proppant slugs, altered mesh types, and adjusted ramp schedule; (9) adjust treatment fluid design (25-lb gel loading instead of 40-lb gel loading); and (10) implement flowback and flowrate control. Implementing these recommendations, Helis deviated from conventional Williston Basin philosophy and drilled 30 "1280’s" in 2010-2012. These wells resulted in ~1,500 bopd with a maximum of 2,500 bopd and EUR’s of ~1,200 MBOe. They are among the best wells in the Williston Basin. In comparison, direct offset well EUR’s averaged less than 750 MBOe. The success of these wells is not the result of one breakthrough but rather the result of sound changes to engineering techniques that were carried out systematically. Applying these engineering practices, maintaining strict adherence to recommended practices, and not making drastic, unfounded changes ultimately optimized production in this Bakken project.
Innovative Pressure-Actuated Toe Sleeve Enables True Casing Pressure Integrity Test and Stage Fracturing While Improving Completion Economics in Unconventional Resources
Authors: Canning Sean , Pacey Kendall , Wellhoefer Ben 
Published: November 2013

Abstract
During the past several years, the oil and gas industry has increased the development of unconventional resource plays which are expected to hold the future for energy development in many parts of the world. In order to maximize these new reservoirs, horizontal wellbores are typically drilled, and multiple hydraulic fractures must be created to provide enough stimulated reservoir volume (SRV) to produce the wells economically. A traditional plug and perforate completion methodology has been employed to perform multi-stage fracture treatments, gain wellbore access, and isolate fracture stages. This process contains inefficiencies that can significantly impact economics. When the plug and perforate method is used prior to running perforating guns and a frac plug to depth, a flow path must be created at the toe of the wellbore. Typically, this is achieved by using tubing-conveyed perforating guns (TCP) deployed on coiled tubing (CT) or by a wireline tractor pulling perforating guns deployed on electric wireline (E-line). Although necessary, this process is one of the major plug and perforate inefficiencies noted in the above completion method. While it does allow casing pressure testing (either government-mandated or part of the operator’s well construction "best practices") prior to fracturing operations, it significantly impacts economics.
To address the inefficiencies, new technologies that seek to eliminate these problems, and thus, improve well economics are being developed. This paper explores an innovative pressure-actuated toe sleeve, which can eliminate running TCP on CT or perforating guns on E-line for initiating a flow path but still allows a casing pressure test to be run. Additionally, the pressure-actuated toe sleeve enables this casing test to be completed without having to exceed the casing test pressure to establish the flow path.
The design, testing, and use of the toe sleeve will be discussed in the paper.
A Work Method to Analyzing Friction Factors in Torque and Drag Modeling
Authors: McCormick John , Wilcox David 
Published: November 2013

Abstract
Long horizontal laterals with challenging well geometries and fracturing operations with 20-30 stages are commonplace in the US. Planning for successful completions operations that push the envelope of equipment and lateral reach is critical, and the ability to more accurately account for drag prior to running swell packers and frac sleeves downhole is needed to assist with the reliability of completions operations.
This paper will include an in depth look at the rig data, torque and drag models and the post job friction factors, which are an overall indication of the hole condition, for six wells. The post-job friction factors will be calibrated for drilling the final hole section and running the completions string, then analyzed to consider a link between the two operations. Production data will also be taken into account.
By creating a database of friction factors for completions operations that consider completion type, fluids used, use of centralizers, lithology and work string data, past experience has shown that even offset wells in the Bakken can have significantly varying amounts of drag. Analyzing the friction factors for drilling the final hole section will provide an opportunity to predict the level of drag prior to running the completions string.
This paper will provide the torque and drag analysis of both the drilling and completions operations for seven wells, along with a method to link the two operations. Conclusions will be drawn related to the variance between wells and the ability to predict the success of running completions strings to TD after gathering the hookload data and calibrating a post-job friction factor for the final drilled section of a well.
Although the results of the analysis will best apply to shale plays with similar geometries, the work method presented in the paper is applicable to any well construction scenario.
Integration of Numerical Simulations for Uncertainty Analysis of Transient Flow Responses in Heterogeneous Tight Reservoirs
Authors: Yue Min , Leung Juliana , Dehghanpour Hassan 
Published: November 2013

Abstract
The complex fracture network created by multistage hydraulic fracturing has been recently described by a triple porosity model. Existing triple porosity models typically assume sequential flow from matrix to micro fractures and from micro fractures to hydraulic fracture. Modeling simultaneous depletion of a matrix block into both micro and hydraulic fractures entails solution of a two dimensional continuity equation that is challenging by analytical or even semi-analytical methods. In addition, analysis with analytical models and type-curves provides deterministic and homogeneous estimates, rendering uncertainty analysis of fracture properties difficult.
In this paper, we use a commercial reservoir simulator to solve the transient response in a segment of a hydraulically fractured horizontal well. This is a triple porosity medium in which matrix blocks deplete into the two fracture networks simultaneously. The proposed model is used to analyze the actual rate data from a tight oil well. It is assumed that the obtained results would characterize the mean estimate of the corresponding fracture parameters. Additional heterogeneous models of fracture properties including its total number and intensity (spacing) are assigned stochastically and subjected to flow simulations to demonstrate their impact on production performance. The resulting production profiles converge to those of dual and triple porosity models at the limiting cases. Uncertainties due to pressure interference between natural fractures and inter-well fracture communication are also investigated. The variability (spread) of the simulation results would capture the sensitivity due to uncertainty in fracture distributions. Our results also show that history-matched fracture half-length strongly depends on the number of micro-fractures implemented in the static simulation model. The estimated value of fracture half-length significantly decreases by increasing the number of micro-fractures from zero, representing the dual porosity system.
This paper systematically investigates applying stochastic models of fracture heterogeneity for production data analysis. It illustrates efficient integration of numerical simulations with analytical solutions to quantify the uncertainty in production performance predictions. Information derived from this sensitivity or uncertainty analysis can be used to evaluate existing fracturing operation and to optimize future multi-stage hydraulic fracturing operations.
Geologic Controls of Gas Production from Tight-Gas Sandstones of the Late Jurassic Monteith Formation, Deep Basin, Alberta, Canada
Authors: Zambrano Liliana , Pedersen Per K. , Aguilera Roberto 
Published: November 2013

Abstract
Comparison of rock properties and production performance between the uppermost lithostratigraphic unit ("Monteith A") and the lowermost portion ("Monteith C") of the Monteith Formation in the Western Canada Sedimentary Basin (WCSB) in Alberta is carried out with the use of existing gas wells. The analyses are targeted to understand the major geologic controls that differentiate the two strata.
The approach involves multi-scale description and evaluation techniques of cores and drill cuttings, including multiple laboratory measurements of key reservoir parameters. The ultimate goal is to understand the distribution of reservoir quality in each stratigraphy unit within the Monteith in the study area.
This study comprises basic analytical tools available for geological characterization of tight gas Formations based on the identification and comparison of different rock types for each lithostratigraphic unit: depositional, petrographic, and hydraulic. As these low-permeability sandstone reservoirs have been subjected to post-depositional diagenesis, a comparison of the various rock types allows to generate a more accurate reservoir description, and to better understand the key geologic characteristics that control gas production potential.
It is concluded that "Monteith A" Unit has better rock quality than the Monteith C", due to less heterogeneous reservoir geometry, less complex mineralogical composition, and larger pore throat apertures. These results are linked successfully with Monteith production capabilities.
Modeling the Failure of Cement Sheath in Anisotropic Stress Field
Authors: Bui Binh T. , Tutuncu Azra N. 
Published: November 2013

Abstract
The primary objective of a cementing job is to create a stable mechanical link between the casing and formation. This link provides a strong support for the casing and isolates different zones to prevent any contamination to aquifers during the lifecycle of the well. The damage of the cement sheath may result in contamination of drinking water resource and negative environmental impact. Hence, the loss isolation of the cement has received much attention from researchers and the public.
The possibility of losing the isolation of the cement sheath during the lifecycle of the well is summarized and the potential risk in contaminating underground water formations is discussed in this paper. A mathematical model for predicting the failure of the cement sheath in an anisotropic stress field is presented. The model combines the effect of temperature, the variation of stress around the wellbore, internal pressure, and the integrity of the casing, cement, and rock formation. The objective of the model is to obtain the maximum internal pressure that we can apply on the casing without causing cement sheath failure. A numerical simulator was developed to calculate this maximum pressure for any inclination and azimuth angle. Computational results show that cement sheath failure depends strongly on the in-situ stress field of the surrounding formation. With stronger uniform formation support, the casing and cement can withstand larger internal stress. The failure of the cement sheath is more severe in a highly anisotropic stress field than in an isotropic field. Hence, the assumption of uniform formation stress around the wellbore may cause significant error in predicting failure of the cement sheath.
The results of this study provide petroleum engineers a tool to determine the maximum internal pressure during drilling, production and stimulation to avoid losing cement isolation. It is recommended to use this model to check the integrity of the wellbore during any operations during the lifecycle of the well.
Transitioning of Existing CO2-EOR Projects to Pure CO2 Storage Projects
Authors: Jafari Alireza , Faltinson John 
Published: November 2013

Abstract
The fundamental distinction between a CO2-EOR project and a CO2 Storage (CCS) project is that the former aims to maximize oil production while minimizing CO2 retention until the oil production becomes uneconomic and the project is abandoned, while the objective of the latter is to store as much CO2 as possible during and after cessation of oil production. A new transition scheme between these two main phases is proposed and described here. The objective of this transition hybrid scheme is to maximize CO2 storage while continuing oil production which otherwise would have been uneconomic. This will create additional storage space in the reservoir by producing incremental oil, with the reservoir produced water being disposed of in another formation.
A hypothetical reservoir simulation model is used to illustrate the shift over time from a conventional CO2-EOR project to a hybrid CO2-EOR/CO2 storage scheme and then to a pure CO2 storage scheme. The most common case of primary-water flood-water alternating CO2 gas (WAG) injection was simulated to mimic a typical oil pool development history. Insertion of the distinct hybrid transition phase between the end of the CO2-EOR operation and the initiation of a pure CO2 storage operation leads to an incremental oil recovery factor of approximately 9% OOIP (a function of the residual oil saturation after the end of the CO2-EOR operation). In other words, cases with the lowest recovery factor (highest residual oil) after CO2-EOR operations and just before the start of the hybrid CO2-EOR/CCS phase could potentially deliver the highest incremental oil recovery factor during this hybrid phase. More importantly, it is shown that the implementation of a hybrid scheme significantly increases the amount of CO2 storage in the reservoir, by up to 67%.
In conclusion, the advantages of having a hybrid CO2-EOR/CCS phase between the end the commercial CO2-EOR operation and pure CO2 storage phase are twofold: 1) generating oil sales revenue to offset some of the costs associated with CO2 capture, transportation and storage by delivering some incremental oil production, and 2) storing significantly more CO2 in the reservoir by creating additional voidage by producing incremental oil and water.