bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case Studies and Best Practices for Installation of Openhole Multistage Completions Systems in Wells Drilled Underbalanced
Authors: Bonar John , Snyder D. J. , Miller Brittany , Jeffers Lonnie 
Published: June 2014

Abstract
Underbalanced drilling has been proven to mitigate formation damage, increase rate of penetration (ROP), and reduce differential sticking of the drill string. This paper describes the benefits of using open hole multistage (OHMS) completion systems in unconventional wells that have been drilled underbalanced. While underbalanced drilling and completion is not the standard, it is being utilized significantly in the United States due to reservoir characteristics.
This paper discusses four types of underbalanced wells where open hole multistage completion systems have been installed: air drilled and nitrogen fractured, low bottom hole pressures, lost circulation scenarios, and those drilled underbalanced for reservoir benefits. Each scenario offers its own unique advantages specific to the reservoir, but also distinct operational challenges.
Detailed discussion of the formation characteristics, and drilling, and installation operations for each of the four case study scenarios of underbalanced wells coupled with OHMS completion systems is provided. Case studies covering examples in shale, sandstone and carbonate plays in the United States are presented.
With over a thousand wells completed with OHMS systems in managed pressure situations, this paper will provide a detailed evolution of operational best practices for installation of OHMS systems in these wells. Therefore, the information presented will address operator concerns regarding the risk of completing underbalanced wells with multiple tools on a single casing string.
Development of a New Continuous Flow System for Managed Pressure Drilling
Authors: Cunningham J. , Bansal R. K. , George G. , De Leon E. 
Published: June 2014

Abstract
Continuous circulation of drilling fluid offers many benefits including increased control of downhole pressure in relation to pore and fracture pressures along with enhanced wellbore cleaning. While the concept of continuous circulation has been known for a long time, it has not been until recently that development of reliable systems have begun turning up. Continuous circulation provides an uninterrupted stream of data from sensors mounted downhole and on surface equipment even while making a connection, thereby never interrupting equivalent circulating density.
Weatherford has developed a sub based continuous flow system (CFS) with an automated control system for switching mud flow between the top drive and side flow port. During conventional drilling operations, CFS subs are passive drill string components. When a new stand needs to be added, a CFS sub connected to the stand already drilled into the well is positioned in the rotary table and a clamp carrying a side flow line is attached to it. Once the clamp has been securely attached, rig hands can move off the rig floor with the rest of the operation taking place from a remote control panel. At this point CFS sub works like a three-way valve. When a sleeve inside CFS sub is pushed upward, it opens a side flow port on the sub simultaneously closing an internal valve to cut off flow from top drive. With concurrent operation of mud valves on a manifold skid, mud flow is redirected from the top drive to side flow port before breaking the top drive connection and back to the top drive after a new stand has been connected. Continuous flow system can be used during trip-in and trip-out operations in an almost identical manner.
Significant strides have been made to introduce a new system with input from customers and exhaustive testing. The process of developing a new product can be long and tedious. It is important to lay out a road map to success not only with a thorough testing program but to make sure that once it has been tested the product is suitable to be utilized for field trials.
MPD Training Competencies: The Challenges of a Young Product Line
Authors: Haggins Ryan 
Published: June 2014

Abstract
Managed Pressure Drilling (MPD) continues to offer a solution to today's growing number of previously "undrillable" technically-challenging wells. With more operating companies looking to incorporate MPD into their well designs and programs, service companies are facing a severe shortage of experienced field personnel capable of meeting this demand. To remain successful, the industry must be able to recruit, train and drive new personnel to competency in a timely fashion, minimize costs, and maximize productivity for the product line.
Training challenges faced by a young product line like MPD include the recruitment of competent field personnel on the rigs; the creation of training and competencies programs geared towards specified job roles; the development of informed instructors and mentors; and the implementation of an effective training system.
In this paper we will suggest the next steps of having a complete development program that focuses on training through a combination of computer based training (CBT), classroom training, and simulation with a hand's on equipment component. Competency that has specific performance criteria the employees will have to meet before advancing to the next level and a mentoring program through on the job learning. These three foundations will re-enforce concepts, techniques, and applications of MPD and ensure the industry will have a trained and competent work force that will meet the growing demand of this young product line.
Modeling Analysis of Transient Pressure and Flow Behavior at Horizontal Wells with Multi-Stage Hydraulic Fractures in Shale Gas Reservoirs
Authors: Wang Cong , Wu Yu-Shu 
Published: June 2014

Abstract
Handling flow through fractured media is critical for transient pressure and flow analysis in shale gas reservoirs, because gas production from such low-permeability formations relies on fractures, from hydraulic fractures and fracture network to various-scaled natural fractures, to provide flow channels for gas flow into producing wells. This study presents a numerical investigation of pressure and flow transient analysis of gas production from a horizontal, multi-staged well in shale gas reservoirs. A specialized three-dimensional, two-phase simulator is developed and used for this purpose, which incorporates known nonlinear flow behavior in shale gas reservoirs. First we discuss a multi-domain, multi-continuum concept for handling multi-scaled heterogeneity and fractures, i.e., using hybrid modeling approaches to describe different types and scales of fractures from explicit modeling of hydraulic fractures and fracture network in simulated reservoir volume (SRV) to distributed natural fractures, microfractures, and tight matrix. Then sensitivity studies of transient pressure responses and flow rates are presented with respect to hydraulic fractures geometry, stimulated reservoir volume (SRV), and natural fracture density. We will also compare the behaviors with two different interporosity flow assumptions, fully-transient and quasisteady state flow. Unlike conventional reservoirs, their difference cannot be ignored due to the extremely low shale matrix permeability and significant gas compressibility. Specifically, we will analyze a field example from Barnett shale to demonstrate the use of results and methodology of this study.
Unconventional Asset Development Work Flow in the Eagle Ford Shale
Authors: Cook David , Downing Kirsty , Bayer Sebastian , Watkins Hunter , Sun Chee Fore Vanon , Stansberry Marcus , Saksena Saurabh , Peck Doug 
Published: June 2014

Abstract
The Eagle Ford Shale is recognized as the largest oil and gas development in the world, based on capital investment (Wood Mackenzie 2012). Development typically consists of horizontal wells stimulated with multiple hydraulic fracture stages. Almost $30 billion will be spent developing the play in 2013, and optimizing the completion design and spacing of these wells can result in large rewards for the companies involved. This paper presents a pragmatic integrated workflow, used to optimize development and guide critical development decisions in the Black Hawk field, Eagle Ford Shale. Geoscientists, reservoir, and completion engineers worked collaboratively to identify the optimal completion designs and well spacings for development focus areas. Multiple simplistic simulation models were history matched to existing production wells. Wide uncertainty exists in many key reservoir and completion parameters. Using stochastic realizations from ranges of key properties, uncertainty was reduced using the history matching process. The resulting calibrated reservoir scenarios formed the basis of optimization studies for development drilling and down spacing. Completion design parameters, including fracture stage length, perforation clusters per stage and landing point for the lateral, were evaluated in hydraulic fracture models. The resulting fracture geometries were simulated and the optimum completion design, and well spacing determined for each area. The optimal development was shown to vary by region, due to changing reservoir, fluid and geomechanical properties. The use of multiple subsurface realizations, spanning an appropriate range of uncertainty, was critical to the success of this study. Economic analysis across a range of potential outcomes enabled robust development decisions to be made. As a result of this work, field trials to test proposed changes to the completion have been initiated, and development drilling plans updated to reflect the optimal well spacing for each lease.
Evaluating the Benefits of Zipper Fracs in Unconventional Reservoirs
Authors: Sierra Leopoldo , Mayerhofer Mike 
Published: June 2014

Abstract
In cemented and cased wells, perforation cluster spacing is optimized based on the type of reservoir fluid, permeability, fracture conductivity, proppant distribution, and associated stresses to place multiple fractures along horizontal wellbores. Specifically, in very low-permeability reservoirs, the requirement for smaller perforation or fracture spacing might not be possible because of the geomechanical interference between fractures. In this case, the commonly used zipper-frac technique can provide a means to create fractures in projects with closer spacing.
The benefits of zipper fracs can be maximized by generating proper fracture geometry and properly staggering the perforation/fracture system. This paper reviews and discusses numerical reservoir-modeling results of zipper fracturing that demonstrate the individual or combined effects of the perforation/fracture staggering, comparing these to the fracture length, fracture overlap, fracture conductivity, and/or proppant distribution effects of a conventional completion that does not use the staggered zipper-frac approach. The simulation results are assessed over a wide range of unconventional reservoir permeabilities for both gas and light oil.
Imbibition Characteristics of the Barnett Shale Formation
Authors: Morsy Samiha , Sheng J. J. 
Published: June 2014

Abstract
In order to understand the effect of injected stimulation fluids on nano-darcy permeability, naturally fractured shale reservoirs, an integrated study of spontaneous imbibition has been performed. In this study, oil recovery during spontaneous imbibition in naturally fractured shale samples was improved using different water formulations. Different water solutions were formulated by adding different amounts of HCl and NaOH to either distilled water or 2 wt% KCl-base brine solution. Eight water formulations, distilled water, 2% KCl brine, low pH HCl solutions (0.74-1.2), and high pH alkaline solutions (11.7-12.4) were examined to recover oil from shale rocks. Outcrop samples from the Barnett shale formation were used in this study. The samples were 2.54 to 3.81 cm in diameter and 0.762 to 5.08 cm in length. Firstly, we studied the average porosity of the used samples using CT Scanning. The average porosity was around 7%. Secondly, we studied the rock stability and spontaneous imbibtion of the different Barnett samples in distilled water, 2 wt% KCl, low pH solutions (0.74- 1.2), and high pH alkaline solutions (11.7-12.4). During the spontaneous imbibition, the maximum oil recovery was 24% using distilled water and low pH solution of pH0.74 (3 wt% HCl in 2 wt% KCl base brine solution). Clay swelling can contribute to the Barnett oil recovery improvement by creating along bedding cracks. Oil recoveries from the Barnett shale can be improved by 56% when used 2 wt% NaOH solution and 88% when used 3 wt% HCl when added to 2 wt% KCl simulation base fluid. High pH solutions did not improve oil recoveries from the Barnett samples when added to distilled water due to pore plugging resulted from the combination of clay swelling with mineral dissolution. Low pH solutions showed along bedding cracks similar to distilled water effect on the Barnett shale samples that helped recovery accelerations, while higher pH solutions showed sever samples damage with higher alkaline concentrations (2 wt% NaOH).
Development of a Stress Dependent Permeability Model in Tight Gas Reservoirs: A Case Study in Cooper Basin, Australia
Authors: Rezazadeh Mehrdad , Haghighi Manouchehr , Pokalai Kunakorn 
Published: June 2014

Abstract
Substantial amounts of gas are accumulated in tight sand reservoirs in Cooper basin, Australia. This basin has a complex geomechanical stress regime. It is believed that the orientation of the minimum horizontal stress is changing and also there is a stress dependent permeability in this basin. These characteristics have a major impact on the gas recovery from different fields in Cooper basin.
It is well known that permeability decreases in sandstone reservoirs when the net confining stress on the rock increases as the gas pressure in the reservoir decreases, so permeability is reduced by gas production. This permeability reduction is more pronounced in tight sand reservoirs due to shear dilation of micro-fractures. In order to model stress dependent permeability, a fully coupled finite element geomechanical reservoir simulations is needed. However, since a large number of data and high computational time is required for this kind of modeling, stress dependent permeability model is a short cut for reservoir simulation. This paper presents an alternative approach of partial coupling of geomechanics and reservoir simulation in which only a finite difference simulator is used with much less computational time and lower cost.
In order to prove stress dependent permeability and develop a model, first a three dimensional hydraulic fracture model is constructed based on wire-line logs and mini-frac tests, then the resulting fracture geometry and conductivity are used as input data for dynamic reservoir flow simulation. We found that the reservoir permeability is changing at different time periods during pressure and production history matching.
In this paper a stress-permeability relationship was developed by assuming a fully elastic fractured network of flow path to the wellbore in a hydraulically fractured well. Then, this model was tested by a partially coupled geomechanical simulation in Big Lake field in Cooper basin. The results show that our approach has better predictions than when the permeability is assumed to be constant. By this procedure not only the predictions are improved but also the computational time is reduced.
Well-Spacing Study to Develop Stacked Tight Oil Pay in Midland Basin
Authors: Cullick A. S. , Carrillo M. , Clayton C. , Ceyhan I. 
Published: June 2014

Abstract
Tight formations are being developed by drilling in the Midland Basin. Target intervals include Clearfork, Wolfcamp, Spraberry, Strawn, Cline, Atoka, and Mississipian formations, which are usually found between 6000 feet and 11,500 feet true vertical depth (TVD). Development is typically with vertical wells, which are stimulated with multiple hydraulic fractures targeting the expected pay intervals and are produced commingled. A significant challenge for operators is determining the optimum well locations and spacing for efficient reserve development. Operators use various field data and analytics to determine well spacing, although limited data pose challenges to making the best decisions. Numerical models can yield insights about drainage patterns and potential interference. This paper reports a case study using a geologic model, hydraulic stimulation models, and a reservoir simulation model to evaluate reduced well spacing impacts on recovered oil and economics. A three-dimensional geologic model was constructed for a 14-section area in the Midland Basin. An extensive core-log statistical study yielded calibrated rock types at the wells. Reservoir and geomechanical properties were then spatially distributed using geostatistical techniques subject to data constraints. A reservoir simulation model was then utilized on a sector area of the full model. The sector model was history-matched to early production data and historical type curves. Each well had 10–12 fracture stages, which were explicitly modeled using parameters derived from post-execution analysis of fracture job data. The paper presents history-matched simulation models that were executed to predict production and economics for 40-acre and 20-acre well spacing cases.
Analysis of Gas Production From Hydraulically Fractured Wells In The Haynesville Shale Using Scaling Methods
Authors: Male Frank , Islam Akand W. , Patzek Tad W. , Ikonnikova Svetlana , Browning John , Marder Michael P. 
Published: June 2014

Abstract
The Haynesville Shale is one of the largest unconventional gas fields in the US. It is also one of the deepest, with wells reaching more than 10,000 feet below ground. This uncommon depth and overpressure leads to initial reservoir pressures of up to 12,000 psi. These pressures are uniquely high among shale gas reservoirs, and require special treatment. We show that the methods developed by Patzek, et al., PNAS, 110, 19731-19736, can scale all individual wells' gas productions to fit upon a single, universal curve. Haynesville wells can take months or years for flowing tubing pressure to stabilize, so we modified the type curves to take this into account. Furthermore, we introduce a PVT solver in order to calculate gas properties at up to reservoir pressures. When we apply the scaling theory to 2,199 individual well productions in the Haynesville, we find 1,580 wells which have entered exponential decline due to pressure interference. We use a simple physical model to determine the time to interference for wells with geologic parameters typical of the Haynesville, and use this to determine a field-wide permeability from the wells where we have observed pressure interference. From this, we arrive at time to interference for the remainder of Haynesville wells, and use this to arrive at production forecasts for all individual wells.
Development and Field Applications of Highly Conductive Proppant-free Channel Fracturing Method
Authors: Inyang U. A. , Nguyen P. D. , Cortez J. 
Published: June 2014

Abstract
Various methods are used to overcome choking effects in propped fractures to enhance and maintain well productivity (particularly in low-permeability reservoirs). Choking effects can result from permeability damage caused by fracturing gel residues, low-proppant concentrations, proppant crushing from high closure stresses or use of low-quality fracturing sand, or embedment/intrusion of formation materials into the proppant pack. This paper describes the development and field applications of a new well stimulation method for generating stable and highly conductive channels within a propped fracture to help maximize the transport capability of hydrocarbons from the formation reservoir to the wellbore.
Extensive laboratory experiments and large-scale testing were performed to evaluate the formation and stability of proppant aggregates and proppant-free channels (PFCs). Proppant-laden slurry (prepared by mixing fracturing sand coated with an agglomerating agent in a gel fluid) and crosslinkable proppant-free spacer fluid were pulsed intermittently to form proppant aggregated masses surrounded by proppant-free gel slugs. Highly conductive channels were formed surrounding the proppant aggregates after crosslinked gel slugs were broken and removed from the propped fracture, leaving behind proppant aggregated masses that supported the closed fracture.
Field trials were performed in unconventional and conventional oil formations. Injection pressures of proppant-laden slurry and proppant-free spacer using the pulsing approach were found to be significantly lower than those applied with conventional hydraulic fracturing treatments, indicating this new method helps alleviate the risks of screenout, as the proppant-free spacer sweeps and mitigates the proppant buildup in the near-wellbore (NWB) area. Field results showed production in wells treated with the proppant-free channel fracturing method increased significantly, even using 40% less total proppant, compared to production of offset wells in which conventional fracturing treatments were performed.
Regional Impacts of Lithologic Cyclicity and Reservoir and Fluid Properties on Eagle Ford Shale Well Performance
Authors: Tian Y. , Ayers W. B. , McCain W. D. 
Published: June 2014

Abstract
Since 2008, the Eagle Ford Shale has been one of the most active U.S. oil and gas plays. Regional variations of the frequency (cyclicity) and thickness of organic-rich marl and limestone interbeds influence well completion design, and these variations may be related to well production performance. To better understand the impacts of lithologic cyclicity and reservoir and fluid properties on well performance, we conducted an integrated, regional study using well logs, production data, and PVT reports.
Regionally, the Eagle Ford Shale is composed of 3 units. The Lower Eagle Ford consists of cyclic, interbedded organic-rich marl and limestone. To analyze lithologic cyclicity of the Lower Eagle Ford Shale in South Texas, We evaluated gamma ray logs from more than 500 vertical wells. A Matlab script was developed to count the numbers of organic-rich marl and limestone interbeds. Average bed thickness was calculated at each well and was mapped regionally. The numbers of both limestone and organic-rich marl interbeds increase from less than 2 in the northwest to more than 20 on the southeast. Lithologic cyclicity is greatest in La Salle and Karnes Counties, which are the most productive gas and oil regions, respectively.
Eagle Ford Shale reservoir and fluid properties from PVT reports were mapped to further evaluate regional variations of fluid types and well performance. Reservoir pressure, pressure gradient, oil gravity, and gas specific gravity were mapped. Reservoir pressure and pressure gradient are greatest on the northeast. Oil gravity and gas specific gravity maps suggest increasing thermal maturity from northwest to southeast, with increasing depth.
Well production rates are strongly influenced by lithologic cyclicity, pressure, and fluid properties. Understanding these relations in the lower Eagle Ford Shale should assist with optimizing completion design and stimulation strategies. The results of this study provide a better understanding of Eagle Ford Shale reservoir characteristic and well performance, and the study approach may be used to assess productivity of other shale plays.