bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multi-Porosity Simulation of Unconventional Reservoirs
Authors: Hinkley Richard , Gu Zhiqiang , Wong Terry , Camilleri Dominic 
Published: November 2013

Abstract
Today, most unconventional reservoir simulations are performed within a single-porosity framework. Very fine, high permeability gridblocks are used to represent the discrete fractures. Geometric spacing of blocks away from the fractures is necessary to capture the pressure gradients and simultaneously keep the number of gridblocks manageable. Without further subgridding the effects of desorption, diffusion, and transport through macro- and micro- fractures must be lumped resulting in a possible loss of transient fidelity. Yet these processes readily lend themselves to analysis with additional porosity types where the transport sequence can be preserved and studied. In this paper, we use a full production simulator to explore the advantages and disadvantages of simulating unconventional reservoirs with one-, two-, three-, and four-porosity systems. Kerogen, macro-fractures, micro-fractures, and an inorganic matrix are represented directly in the four-porosity system.
Smart-Engineered Ball Seat System to Optimize Flow Area in Multi-Zone Fracturing Treatments
Authors: Carrejo Nick , Wibowo Hendra , Espinoza Omar R , Gaudette Sean L 
Published: November 2013

Abstract
Conventional hydrocarbon reservoirs are being depleted, and the demand for energy grows as the world’s population progresses. Unconventional reservoirs are playing an increasingly important role in today’s effort to meet these growing demands. Two common forms of unconventional resources are the extraction of heavy oil or oil sands and the hydraulic fracturing of tight, hydrocarbon-bearing shale. Hydraulic fracturing is a technique made popular by the results yielded in the Barnett Shale basin in 1998. Of these two, hydraulic fracturing is more commonly used due to production economics. Over the last 15 years a significant effort has been made to increase the efficiency of this process. A common method of hydraulic fracturing is using a tripping ball and ball seat system. This system leads to a reduction in flow area. In addition, tripping balls can produce significant production risks. The production risks include lost production time if a stuck ball requires the well to be worked over. Lost flow area can be detrimental if the tripping ball remains in the lateral. A new smart-engineered composite has been developed to significantly optimize this process and provide flow assurance after the hydraulic fracture treatment. High-strength corrodible material (HSCM) is a metallic composite. HSCM is designed for the ball-actuated system used during hydraulic fracturing. This paper will explore the development and reliability of this new technology, and discuss development of a new interventionless ball seat system.
Shale Failure around Hydraulic Fractures in Water Fracturing of Gas Shale
Authors: Ji Lujun , Geehan Thomas 
Published: November 2013

Abstract
Even though shale has traditionally been considered a hydrocarbon source rock and/or seal rock, some gas bearing shales have been recognized as major reservoir rocks for unconventional hydrocarbon resources. The exploitation of gas shale across North America has generated much activity in the drilling and completion sector of the oil and gas industry, including drilling horizontal wells and multi-stage fracturing with water-based fracturing fluids. During water fracturing, the shale will interact with water and create consequences (hydration, dehydration, fractures etc.) as that happens in drilling. The consequences from this shale/water interaction will not only alter the shale mechanical properties, but also induce stress changes in the shale. These changes may induce favorable or unfavorable fractures in the shale/water interacted zones.
This paper first outlines lab observations of the shale/water interactions which generating fractures in gas shale. Then, a stress model is developed with poro-elasticity effect and simulation method for studying stress changes due to shale hydration in near-fracture zones. This paper also describes a sample application of the models to investigate stress changes and potential shale failures in shale around major hydraulic fractures in shale gas.
The study presented in this paper that it was mechanically possible to induce multiple secondary fractures around major hydraulic fractures via shale hydration. The modeling in this paper completes the preliminary study and provides a foundation for more complex scenarios in future studies focusing on water fracturing and horizontal well drilling in gas shale. It also provides some new ideas of optimizing hydraulic fracturing in gas shale.
Understanding Flowback as a Transient 2-Phase Displacement Process: An Extension of the Linear Dual-Porosity Model
Authors: Ezulike D. O. , Dehghanpour H. , Hawkes R. V. 
Published: November 2013

Abstract
Existing rate transient models for fractured horizontal wells assume single-phase fluid flow. This assumption is violated in early times, when hydraulic fractures (HF) are filled with fracturing water and hydrocarbon. This calls for a model that captures the transient 2-phase (gas/oil + water) flow in HF, and can be used for history matching rate and pressure data measured during flowback operations. Existing models for analysing multiphase data from solution-gas drive and high-water-saturation conventional reservoirs cannot be applied to flowback data because of simplifying assumptions such as (1) constant average phase saturation with time, (2) constant rate or pressure well constraint and (3) radial flow. This paper extends the existing linear dual-porosity model (DPM) and develops a flowback analysis model (FAM) which accounts for transient multiphase flow in HF.
The proposed model adopts an explicit dynamic-relative-permeability (DRP) function of time for hydrocarbon phase in the fracture network to account for water-saturation drop. This model assumes that water-saturation drop with time causes a corresponding non-linear increase in hydrocarbon relative-permeability in HF. The DRP function is obtained from analysing cumulative hydrocarbon + water measured during flowback operation and drainage relative-permeability curves from existing literature. Fifteen tight oil, tight gas and shale gas wells completed in the Bluesky, Cardium, Evie, Muskwa and Otter-Park Formations were used for this study. The resulting DRP parameters control the rate of water-saturation drop in HF (clean-up rate). DRP is incorporated into the existing DPM to obtain FAM flow equations. This paper attempt solving these equations with Mellin transforms under variable bottom-hole rate and pressure well constraints.
FAM converges to the existing DPM at the limit of residual water-saturation. DRP captures the fluid physics from flowback phase till the "full" hydrocarbon production phase in the life of a multifractured horizontal well. The application of FAM on transient 2-phase flowback data (rate + pressure) could help estimate key reservoir parameters (e.g. effective HF half-length) and evaluate flowback performance (e.g. percentage of total inject fluid left in HF and matrix and the speed of HF clean-up). Results from this study is applicable for interpreting 2-phase flowback data from multi- fractured horizontal wells completed in tight and shale reservoirs. This study allows the industry to forecast hydrocarbon recovery from flowback data and estimate/predict the effectiveness of flowback operations.
Flowback Volumetric and Chemical Analysis for Evaluating Load Recovery and Its Impact on Early-Time Production
Authors: Ghanbari Ebrahim , Abbasi Majid Ali , Dehghanpour Hassan , Bearinger Doug 
Published: November 2013

Abstract
Field studies demonstrate low flowback efficiency determined by volumetric analysis of injected and recovered fracturing water. However, the reasons for inefficient water recovery, and its impact on short-term and long term production are poorly understood. Furthermore, volumetric water analysis is not sufficient for determining the source of recovered water and the true load recovery. This paper aims at understanding how flowback efficiency is related to the imbibition process, presence or absence of natural fractures, and the complexity of induced fracture network.
We interpret the flowback rate and salt concentration, measured from several multi-fractured horizontal wells recently completed in different members of the Horn River basin. We also measure and analyze water imbibition and salt diffusion rate in actual cores drilled from the same shale members. The wells are classified into those with 1) low water and high gas production, 2) high water and low gas production. This classification is explained by lab imbibition data and possible fracture patterns. Furthermore, the flowback salt concentration change is explained by the diffusion data measured in the laboratory. This systematic study provides a practical database for understanding the factors impacting the water recovery that will potentially help the operators to optimize the flowback operations, and obtain useful information about the induced fracture network.
Stable Fracturing Fluids from Waste Water
Authors: Kakadjian Sarkis , Thompson Joseph , Torres Robert , Trabelsi Siwar , Zamora Frank 
Published: November 2013

Abstract
Environmental concerns and public opinion have elevated the visibility of hydraulic fracturing. Currently oil companies and operators acquire fresh water for fracturing treatments on the front end and pay to dispose or transport the flowback or produced water on the back end, increasing dramatically the cost of the hydraulic fracturing job. We report a newly developed fracturing fluid system utilizing 100% untreated produced water which eliminates the upfront costs of purchasing fresh water. In addition, the back end costs are significantly reduced by transporting produced and/or flowback water to locations for re-use rather than to disposal well(s) located miles away or even in other states.
This new system uses conventional gelling agents and crosslinkers used in active US shale plays, addressing the fracturing focus initiative.
This new fluid system was developed for temperature ranges between 120-300+ °F. Field tests prove shear stability and good proppant transport at 20 BPM through a 1.25 in sliding sleeve baffle. The fracturing fluid system can be designed for instant or delayed crosslinking in recycle water with total dissolved solids exceeding 300,000 mg/L with hardness exceeding 30,000 mg/L. Another concern in the past was the presence of boron in produced water. This system can be used in water containing boron levels exceeding 500 mg/L.
The code for recycle water has been broken utilizing this unique fracturing fluid system designed to conserve fresh water aquifers and recycle produced and flowback waters, reducing significantly disposal costs.
This paper reports laboratory testing of the fluid characteristics in untreated produced water from the Bakken as well as the outcome of hybrid fluids in field applications, recommendations for field applications and economic impacts on fracturing fluid systems.
Study on Gas Permeability in Nano Pores of Shale Gas Reservoirs
Authors: Guo Chaohua , Bai Baojun , Wei Mingzhen , He Xiaoming , Wu Yu-Shu 
Published: November 2013

Abstract
Producing gas from shale gas reservoirs has played an increasingly important role in the volatile energy industry over recent years in North America for considerable volume of natural gas stored in the reservoirs. Unlike conventional gas reservoirs, the gas flow in shale reservoirs is a complex multi-scale flow process and has special flow mechanisms. Most importantly, the shale gas reservoir contains a large portion of nano pores. The study of flow in nano pores is essential for accurate shale gas numerical simulation. However, there is still not a comprehensive study in understanding how gas flows in nano pores.
In this paper, based on the advection-diffusion model, we constructed a new mathematical model to characterize gas flow in nano pores. We derived a new apparent permeability expression based on advection and Knudsen diffusion. Acomprehensive coefficient in characterizing the flow process was proposed. Simulation results were verified against the experimental data for gas flow through nano membranes. By changing the comprehensive coefficient, we found the best candidate for the case of Argon with membrane pore diameter 235 nm. We verified the model using different gases (Oxygen, Argon) and different pore diameters (235 nm, 220 nm). The comparison shows that the new model matches the experimental data very closely. Additionally, we compared our results with experimental data, Knudsen/Hagen-Poiseuille analytical solution, and existing researcher’s work. The results show that this study yielded a more reliable solution. For shale gas simulation where gas flowing in nano pores plays a critical role, the results from this work will made the simulation more accurate and reliable.
Analytical Modeling for Geomechanical Changes in Multi-Frac Completions
Authors: Stalgorova E. , Mattar L. 
Published: November 2013

Abstract
There are a number of analytical solutions describing fluid flow through multi-frac horizontal wells presented in literature. This paper presents a way to extend the existing analytical solutions for multi-frac wells to the cases when completion properties (such as fracture conductivity and fracture length) are varying with pressure, and thus with time.
The paper provides a derivation of the suggested method; it uses the formulation of analytical solution of the diffusivity equation based on Green’s function. However it is demonstrated that the same methodology can also be applied to analytical solutions obtained without using Green’s function.
It is believed that in tight formations, production at high drawdown often results in an increased effective stress around the hydraulic fracture system (e.g. Okouma et al. 2011). Higher effective stress causes a decrease in conductivity and/or effective length of hydraulic fractures. Being able to model such a variation of fracture properties with pressure is essential for accurate history matching and production forecasting.
The suggested methodology was validated by comparing the derived solutions against numerical simulation. We found that results obtained by using the suggested methodology and numerical results are in good agreement for single phase fluid and single plane fractures; therefore the suggested method can be applied to analytical models for pressure-dependent multi-frac completions for such cases.
The proposed methodology allows extending available analytical solutions for multi-frac systems in a way that captures the variation of fracture properties with pressure.
First Field Application in Canada of Carbon Dioxide Separation for Hydraulic Fracture Flow Back Operations
Authors: Reynolds M. M. , Ku R. Y. , Vertz J. B. , Stashko Z. D. 
Published: November 2013

Abstract
Carbon dioxide has a long history of successful usage in hydraulic fracturing fluids, dating as far back as 1962. The Canadian Deep Basin area is known to contain many water desiccated natural gas reservoirs which are very amenable to carbon dioxide based stimulation. Another major advantage of carbon dioxide use is to displace fresh water, reducing environmental impacts.
However, in recent years, some operators have moved away from carbon dioxide, due to difficulties related to the contaminated gas stream during fracture flow back operations. An extended period of flaring may be required to reduce the carbon dioxide content to acceptable levels in the sales pipeline. This may contribute to longer periods of flaring, noise and light pollution, increased green house gas emissions, as well as lost revenue to the operator, as otherwise saleable natural gas and gas liquids are being flared.
This paper will outline the development of portable trailer mounted membrane separation equipment for well site separation of carbon dioxide from natural gas. The equipment used and how the process works will be discussed.
Included is documented information from what is believed to be the first successful deployment of this equipment in Canada, on a well site near Grande Prairie, AB. Process information on flow rates, pressures, carbon dioxide inlet and sales content, etc. will be included.
The development of this equipment has many benefits, including reduced flaring, increased sales volumes for the operator, increased royalties for governments, etc. Operators may now take advantage of the reservoir enhancing benefits of carbon dioxide, without any of the negative flow back issues.
In conclusion, we will discuss future research and developments that will reduce or eliminate carbon dioxide venting at the well site.
Highly Reactive Fly Ash Material Improves Economics of Lightweight Cementing with Lower Carbon Footprint
Authors: Jangid Gajendra K , Marjason Stephen R 
Published: November 2013

Abstract
Fly Ash is a light weight residue from coal fired power plants. Blends of Portland cement and Fly Ash are widely used in construction and oilfield industry. The addition of Fly Ash in cement slurries improves compressive strength, sulphate resistance, reduces cement permeability (Golapudi U et al, 1993) and allows lower density slurries while maintaining good mechanical properties (Purvis et al, 2003).
Fly ash is a cheaper, readily available by product. It brings down overall cost by reducing cement consumption. This also helps the environment as every ton of cement produce generates an average of 0.9 ton of CO2. Historically, increasing the Fly Ash ratio above 50% has resulted in significant reduction in its benefits (Purvis et al, 2003) in terms of cement mechanical properties degradation, and especially the compressive strength development at short duration.
A new Highly Reactive-Fly Ash Material (HR-FAM) was developed for higher ratios of Fly Ash in a cement blend. This paper will study and discuss the use of HR-FAM in oil well cementing applications. To prepare lightweight cement systems, various ratios of HR-FAM are blended with neat API Class H cement. All laboratory tests were carried out according to API RP 10B-2 practices for oil well cement. Results were compared against conventional Fly Ash based cement systems. The laboratory test results show that HR-FAM based blends provide better mechanical properties than regular Fly Ash in terms of compressive strength development.
The use of HR-FAM in Portland cement allows slurry designs at lower densities with mechanical properties meeting regulatory requirements. Additionally, it also reduces the consumption of Portland cement up to 33% compared to regular Fly Ash based systems currently used in the oilfield.
The Impact of Well Trajectory on Horn River Shale Gas Well Production in a Multi-Well Pad: A New Approach Using Steady State and Transient Simulation
Authors: Becze A. , Nascimento C. M. , Jackson D. F. , Virués C. J. , Wang A. 
Published: November 2013

Abstract
Shale well production performance is influenced by an array of factors including reservoir quality, wellbore trajectory, well completion, and operating conditions and fluid behavior. Simulation in combination with field measurements offers insights into understanding the interplay between these factors and helps to understand how they impact well performance and, more importantly, how they can enhance well design. This paper focuses on an analysis of the relationship between well trajectory and production performance for three horizontal shale gas wells in the Horn River. It presents liquid holdup data obtained through downhole camera and production logging and compares these with results from integrated modeling and transient simulation technologies. It is important to minimize liquid holdup in the case of shale gas wells as holdup contributes to instabilities and can also plug off contributing stages if those stages are flooded with liquids. Recommendations on horizontal shale well design are presented.
A Practical Guide to Unconventional Petroleum Evaluation Part 2
Authors: Russell Boyd , Freeborn Randy 
Published: November 2013

Abstract
When it comes to decline analysis, very little has changed since Arps’ "Analysis of Decline Curve" paper published in 1945. An evaluator tries to visually match a production profile with either an exponential, harmonic or hyperbolic equation. Certainly, French Curves have been replaced by computers that quickly reflect our best guess, but for hyperbolic wells where the profile cannot be represented by a straight line it’s still a guess, granted it’s an educated guess based on experience. This paper will propose that in many instances, automatic forecasting, using an accurate tool, can replace manual forecasting.
A common problem faced by all evaluators is how to forecast new wells with little production history. In this paper, an analog forecasting method is proposed that yields excellent results both in predicting budget volumes and matching future production profiles. This method will be demonstrated using back casting studies on real world examples.
In SPE 147059, Haskett indicated that the production forecast represented sixty seven percent of the NPV uncertainty in resource play development. Type wells are the primary technique used to generate production forecasts for these new wells. Hence you would expect the oil and gas industry to devote significant research on this topic. When the authors performed a search on SPE One Petro® and Google® for papers about type wells, they only found their two previous papers (SPE 158867 and SPE 162630). In an informal survey of the industry, the authors found that the time slice method of creating type wells was widely accepted. In SPE 158867, Russell et al recommended that the selected well method of creating percentile type wells was preferred over the time slice method. Further research, presented in this paper recommends that the time slice method should be avoided.