bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Pressure- and Rate-Transient Techniques for Analyzing Core Permeability Tests for Unconventional Reservoirs: Part 2
Authors: Clarkson C. R. , Qanbari F. 
Published: November 2013

Abstract
Although matrix permeability is an important control on the commercial viability of unconventional reservoirs, there is no consensus on the appropriate way to measure it in the lab. In previous work (Clarkson et al. 2012), we investigated the use of pressure- and rate-transient analysis (PTA/RTA) methods to analyze data obtained from a new core plug analysis procedure designed specifically to extract information (permeability and pore volume) from ultra-low permeability reservoir samples (core plugs). The new approach involved analysis of rate and/or pressure data from the core test analogously to larger-scale well-test/production data. Although this approach offers some advantages over conventional pressure-decay and pulse-decay test analysis procedures, there are some practical issues related to core measurements to support the analysis that need to be addressed. For example, injection or production rate measurements, which are difficult to perform, were required to implement some of the analysis procedures. Further, in the original work, constant injection rates for the injection/falloff portion of the test, and constant flowing pressures for the production portion of the test, were assumed. In this work, we demonstrate that accurate measurement of injection rates is not necessary to obtain an accurate estimate of permeability and that the analysis methods can be applied for variable injection rates and flowback pressures.
Several permeability estimates are possible during a single test cycle using the procedures described in this work. Permeability may be estimated from the injection/falloff cycle of the test by 1) identifying the end of transient (linear) flow from derivative techniques combined with the distance of investigation calculation and 2) applying a conventional straight-line analysis of linear flow. Two independent estimates may therefore be obtained, but the latter requires estimation of the injection rate history. Similarly, two permeability estimates may be obtained from the production (flowback) cycle of the test using the distance of investigation and straight-line approaches. Both falloff and production analysis procedures are tested by simulating constant and variable injection rates, and constant and variable flowing pressures, respectively. In some cases, particularly with variable rates/flowing pressures, it may not be possible to obtain permeability from all approaches, making multiple, redundant estimates desirable to avoid a failed core analysis. As with the original test procedure proposed by Clarkson et al. (2012), the unique properties of unconventional reservoirs may be accounted for in the new analysis procedure, such as adsorption and non-Darcy flow (slippage and diffusion), and heterogeneities may be detected and analyzed.
We believe this new technique for analyzing core data will considerably improve on current techniques for establishing permeability of unconventional reservoir samples.
Modeling, Testing, and Case Histories of Swellable Packer Casing Anchoring Performance Enable Wells Destined for Plug and Abandon to Become Producers
Authors: Stein Taylor , Tunstall Michael , Wellhoefer Ben , Veillette Christian 
Published: November 2013

Abstract
During the last decade, swellable packer technology has been accepted more readily, and its usage is increasing as a viable method for zonal isolation in the oilfield. During this time, swellable packers have shown a new side to their versatility, as they are now being used in many other applications. These newer applications are requiring that swellable packers provide an anchoring point for the casing or tubing string, and the swellable technology is accepting this challenge by being used to provide this requirement in applications such as casing repair, liner tieback, corroded casing, and multi-stage fracturing.
This paper will review case histories and testing in order to illustrate procedures for developing, simulating and validating swellable-packer anchoring forces that will enable swellable packer technology to be applied in new oilfield applications. This testing and information will show that when the application and well conditions are understood, swellable packer technology can be a viable alternative to cementing of casing strings or expandable casing patches for providing anchoring points and isolation. This application often allows larger IDs to be considered and costs of workover operations to be reduced. Critical aspects such as the swelling fluids, pressure requirements, production/stimulation scenarios, well conditions and goals, and other concerns of the engineering and design process will be discussed. The impact of these parameters will be explained as well as how each is important in designing the swellable packer to meet any oilfield application. Other job design aspects such as simulating the swellable packer behavior and performing necessary laboratory testing to validate the simulation will also be compared to case history results.
Finally, the paper will conclude how swellable packer technology can be used for many applications requiring anchoring forces.
Analysis of Transient Linear Flow in Tight Oil and Gas Reservoirs with Stress-Sensitive Permeability and Multi-Phase Flow
Authors: Qanbari F. , Clarkson C. R. 
Published: November 2013

Abstract
Horizontal wells and hydraulic fracturing are the key technologies that allow commercial production from tight oil and gas reservoirs. However, rigorous analysis of production data from these reservoirs requires incorporation of the impacts of stress-dependent permeability and multi-phase flow. Changes in the stress state of the system during production may reduce the absolute permeability. Furthermore, gas phase formation and flow in presence of supersaturated oil phase affects fluid dynamics in tight oil reservoirs. This study provides a rigorous methodology for incorporation of the effects of non-static permeability and multi-phase flow in rate transient analysis (RTA) of tight oil and gas reservoirs producing at variable rate/flowing pressures during transient linear flow period.
Analytical solutions for the approximate linearized form of the flow equation have been widely used as the basis for RTA tools for conventional reservoirs during transient flow period. However, they lead to considerable error when applied to tight oil and gas reservoirs. In particular, during the transient linear flow period, the slope of the square -root-of-time plot obtained from numerical solution differs from the slope calculated by analytical methods. Efforts have been made by some researchers to obtain a correction factor from the numerical solution of the flow equation to correct the slope of the square-root-of-time plot for single phase flow of gas during transient linear flow period. In this study, an iterative method is used for evaluation of the slope correction factor in the presence of multi-phase flow and non-static permeability for constant-pressure production during transient linear flow period. Further, the correction factor is used for analysis of production data from tight oil and gas reservoirs producing at variable rate/flowing pressures.
The correction factor is used in the analysis of different sets of synthetic production data for tight oil and gas reservoirs. The results show that the correction factor can reduce/eliminate the considerable errors associated with the conventional analytical methods in initial permeability estimation. For multi-phase flow cases, the producing gas -oil ratio (GOR) is used to estimate the oil saturation-pressure relationship in the reservoir, which is required for calculation pseudo-pressure and the correction factor.
The method developed in this study alleviates the need for using numerical simulation models to generate empirical correlations for the correction factor for the square -root-of-time plot. The easy-to-implement iterative procedure of this method only requires the pressure dependencies of the constituent elements of the hydraulic diffusivity. Therefore, this method is applicable for analysis of production profiles for variety of reservoirs with nonlinear flow equations.
Hydrocarbon Recovery Boosted by Enhanced Fracturing Technique
Authors: Allison Dave , Bryant Jason , Butler Jeremy 
Published: November 2013

Abstract
The oil and gas industry has continuously searched for methods to increase the recoverable reserves of known hydrocarbon reservoirs. Keeping in mind that every reservoir will have its own recovery factor, historic numbers indicate that original completions access between 10 to 25% of available reserves, and secondary and tertiary recovery techniques can improve the recovery factor to as much as 25 to 60% of the hydrocarbons in place. With an industry focus on unconventional shale and its ultra-low permeability, the recovery factors are on the lower end of the historic figures. The ultra-low permeability dramatically limits the drainage radius of a given fracture.
A new completion technique is providing a methodology to improve hydrocarbon recovery. This paper presents the results of case studies for two different fields where a deep reservoir diverting technique using environmentally acceptable self-removing diverters has significantly impacted the production from 15 shale wells. Insight is also presented regarding how this deep reservoir diverting technique has the potential to impact a well’s production, spacing, and ultimate hydrocarbon recovery in unconventional shales.
Fully Compositional and Thermal Reservoir Simulations Efficiently Compare EOR Techniques
Authors: Lucia Angelo , Voskov Denis , James Scott C. , Zaydullin Rustem , Henley Heath 
Published: November 2013

Abstract
Primary oil recovery methods in Saskatchewan’s heavy oil basin extract 5 to 10% of the available resource with the vast majority left in the ground and recoverable only through Enhanced Oil Recovery (EOR) methods. Traditional EOR generates steam in surface facilities and injects it underground to mobilize the oil for production with considerable energy losses inherent in the process. R.I.I. North America’s Solvent Thermal Resource Innovation Process (STRIP) technology moves the steam generator underground, reducing the operating and capital costs of a surface thermal production facility by 30% and 50% respectively, and saving more than 30% of the energy typically required for thermal production. STRIP technology combusts methane to produce in situ CO2 and steam. Because CO2 acts as a co-solvent, STRIP outperforms traditional steam-injection technology. This is demonstrated using a breakthrough modeling technique that couples fully compositional and thermal reservoir flow simulation capabilities. This new approach couples FlashPoint’s equation-of-state solver for the multiphase, multi-component, isothermal, isobaric flash problem, GFLASH, with Stanford’s Automatic Differentiation General Purpose Research Simulator for thermal reservoir flow simulations. This new computational framework exploits advanced techniques for skipping phase-identification computations and only uses exact phase equilibria from GFLASH when needed, reducing computational times by one to two orders of magnitude compared to the full rigorous solution.
A Transient Model for the Liquid-Loading Process in Fractured Horizontal Gas Well
Authors: Li Y. , Teng S. , Shi J. , Xu D. , Lei G. 
Published: November 2013

Abstract
Fractured horizontal well is the most important method for the exploitation in tight gas reservoirs or unconventional gas reservoir. And liquid loading may become a serious problem in fractured horizontal wells when gas product capacities are reducing.
This paper will propose a transient model for liquid loading process of fractured horizontal wells over time.it is obvious that these wells have a large stable rate and all fluids produced from reservoir could be carried to the surface when the gas rate is larger than critical rate; then, the effect of liquid-loading makes the gas rate smaller to be a metastable rate as soon as the gas rate is below critical rate.
A model is introduced for understanding liquid-loading process better in fractured horizontal wells. It is assumed that gas and water coproduction and water reinjection both exist in hydraulic fracture. And part of water produced from reservoir is carried to the surface and the rest water will first accumulate at the bottom of the hydraulic fracture with the help of gravity when liquid loading starts and part of water in fracture may reinject into reservoir later. Then, the water column will reach the horizontal section or even get up to the inclined section and the vertical section. Finally, a metastable rate could be observed when water produced from reservoir is equal to the sum of water carried to the surface and water reinjection.
Then, the sensitivity analysis of several parameters such as the fracture parameters (the length, the width, the height, and number of fractures) and water gas ratio of the surface have been taken to influence the metastable rate and the time reached to the metastable rate.
With this model, liquid-loading process in fractured horizontal wells can be understood better and predicted. And it is very important for the optimization of fracture parameters and well production parameters to prevent and control the liquid-loading process.
Optimizing Cyclic CO2 Injection for Low- permeability Oil Reservoirs through Experimental Study
Authors: Wang Zengxiang , Ma Jinhua , Gao Ruimin , Zeng Fanhua , Huang Chunxia , Tontiwachwuthikul Paitoon , Liang Zhiwu 
Published: November 2013

Abstract
Cyclic CO2 huff ’n’ puff process in diverse reservoir conditions, such as immiscible, near-miscible, and miscible, has been tested in the laboratory and applied in the fields as a viable secondary or tertiary means to recover the residual oil in water flooded reservoirs or pressure depleted reservoirs. Recently, petroleum operators have shown increasingly interest in taking CO2 huff ’n’ puff process as a preferred option to extract light oil in low-pressure and low-permeability reservoirs.
In this paper, experimental results from a series of coreflood tests are presented and operation strategies for cyclic CO2 injection are optimized to maximize the light oil recovery factor in a low- permeability reservoir with low original reservoir pressure and while, minimize CO2 utilization. 6 cyclic coreflood tests, 20 cycles in total, are conducted in a 973 mm-long composite core with an average porosity of 9.6% and an average permeability of 2.3mD. The reservoir pressure is 12.9MPa, far below the measured MMP value of 23MPa, which indicates that the reservoir has no sufficient energy support to do primary production. The impacts of primary operational parameters, such as slug size, injection pressure, chasing gas (N2) and CO2 injection rate on the performance have been investigated.
It is concluded that, on the basis of experimental data, 0.1PV seems to be an optimal slug size for the first cycle, with a cycle recovery factor as high as 14.52% when reservoir pressure depleted to 8MPa. The recovery factor is suggested to be sensitive to the maximum pressure and the maximum pressure should be built up to as high as formation permits. In the following cycles, injecting N2 as chasing gas after CO2 injection seems to improve the cycle performance significantly and concurrently reduce the CO2 utilization. The optimal operation should have three cycles and the ultimate recovery factor for these three cycles could reach above 30%. The findings of this paper extend the understanding of cyclic CO2 operation and may be employed as technique reference for cyclic CO2 process operations in low-pressure and low-permeability closed boundary reservoirs.
Hybrid Horizontal in a Foothills Carbonate
Authors: Holan H. , Ziebell T. , Lowen B. 
Published: November 2013

Abstract
This paper will describe the design objectives and choices prior to drilling of the subject well, and modifications to the completion design once well logs were in hand. The well was a test bed to compare the effectiveness of acid fracturing vs. proppant fracturing in a deep gas carbonate reservoir, as well as the technology used to deliver the stimulations, open hole packers vs. cemented in sleeves. In the current low gas price environment, a multiple well drilling program could not be pursued, the budget was limited to one well to test concepts and methodologies.
Aggregate Production Forecasts for Unconventional Resource Drilling Locations Using Monte Carlo Simulation
Authors: Mireault R. 
Published: November 2013

Abstract
As SPEE Monograph #3 notes, few guidelines exist to evaluate unconventional resource plays. The significant variability in well performance that is inherent to resource plays may preclude the use of an analogous "type" well when evaluating undrilled locations, as is done for conventional reserve evaluation. Yet the necessity of having reliable production forecasts as the foundation for sound investment remains.
The paper uses Monte Carlo simulation to generate an aggregated production forecast distribution for multiple undrilled locations from the forecast distributions for the individual locations. From the central limit theorem, the sum of individual production forecasts tends towards the average value for the undrilled well population times the number of locations as the number of drilling locations becomes very large (infinite).
However, in the real world the number of drilling locations is finite and limited so a forecast based on the "average" for the entire population likely overestimates the results for the group. The reason is that well production rates are characterized by skewed (e.g. lognormal) distributions so more than 50% of the wells drilled will produce at less than the average well rate while a few "stars" will perform at rates that are well above the average.
Accordingly, the first wells in a random drilling sequence will likely produce at below average rates. The group rate will continue to lag the population average with each successive well drilled until "luck" intervenes and a location that produces at well above the average is drilled. Consistently overestimating producing rates as a field is developed can lead to marginal economics or even "gambler’s ruin" if the "star" well is not drilled before the entire drilling budget is spent.
To overcome the practical pitfalls of the central limit theorem, Monte Carlo simulation is used to quantify the uncertainty in the production forecasts of a group of wells. A 10-location drilling example illustrates the variance in the forecasts over a 20-year project life. The resulting P90, P50 and P10 production forecasts provide a means to assess the impact of our uncertain knowledge on production rates, cash flows and project economics.
Long Overlooked Residual Oil Zones (ROZ's) Are Brought to the Limelight
Authors: Harouaka A. , Trentham B. , Melzer S. 
Published: November 2013

Abstract
Residual oil zones have been located below oil/water contact of many oil reservoirs (Brownfield’s) in the Permian Basin and elsewhere; they are also present far from main pay zones (Greenfield’s). These ROZ’s were, for a long time, considered an integral part of the aquifer as they have been naturally water flooded at a very low flow rate over geological times.
New thinking is recognizing them as an important hydrocarbon resource with economic oil saturations ranging between 20 and 40 %. They (ROZ’s) are an excellent target for a tertiary recovery process which, in the Permian Basin, is almost synonymous to CO2 injection. ROZ’s are probably the most conventional of unconventional oil resources.
Located right beneath or in the vicinity of fully developed oil fields, these oil zones were a portion of a larger oil entrapment which has been thoroughly water flooded by Mother Nature. Field projects are demonstrating that ROZ’s are both technically and economically viable through a tertiary recovery process.
Several pilots and full field applications are currently being carried out in the Permian Basin and soon to be starting in the Rockies. As their distribution becomes well documented, ROZ’s are expected to account for a substantial increase in oil resources. Those under CO2 injection in the Permian Basin are currently being produced above the estimated rate of 11,000 bopd, keeping in mind that some companies do not report the ROZ zone production separate from the main pay.
Modern oil/water contacts whereas traditionally considered the lowest part of an oil reservoir, ROZ’s are changing that perception and increasing significantly the thickness and lateral extent of several oil fields. In many instances they (ROZ’s) are thicker than the maximum thickness of the known associated primary reservoir. Owing to the large lateral extent of the aquifer flushing process, many green fields are now being recognized at significant distances from fully developed oil fields.
A Semi-analytical Model for Hydraulically Fractured Wells With Stress-Sensitive Conductivities
Authors: Yao Shanshan , Zeng Fanhua , Liu Hong 
Published: November 2013

Abstract
The common methods to model hydraulic fractures are based on the assumption of constant fracture conductivity. However, in some cases the hydraulic fracture conductivity may be a function of stress/pressure, and thus significantly change during production. It is reported that the hydraulic fracture conductivity may be reduced from a few to hundreds of folds in the literature.
This paper presents a semi-analytical model to facilitate transient pressure analysis for hydraulically fractured wells with stress-dependent hydraulic fracture conductivities. This model is developed for both hydraulically fractured vertical wells and multi-stage fractured horizontal wells. Considering the stress-dependent hydraulic fracture conductivities leads to the mathematical model being strongly non-linear. In order to solve the problem, hydraulic fractures are discretized into several slab source segments. The fluid flow from formation directly to fractures and flow inside fractures are calculated at each time step. Pressure distribution can be computed with complete fluid flow distribution. Then, the conductivities of hydraulic fractures are updated based on the pressure distribution. In each time step, an iteration process is used to deal with the relationship between fracture conductivities and the pressure.
The effect of stress-sensitive conductivities on transient pressure behavior is studied and type curves are documented. As the fracture conductivity decrease, the pressure and corresponding pressure derivative curves rise quickly and when the conductivity declines to the minimum value, the increasing pressure drop slows down. Therefore, a hump is formed on the pressure derivative curves. The slope of the hump is close to unit in log-log plot. The time of the hump's appearance and its size are determined by characteristics of hydraulic fractures, reservoir properties and production rate. Field examples from fractured vertical/horizontal wells are analyzed and reliable results are obtained.