bluuebunny/crossref_metadata_2025 huggingface dataset:
Phase Behavior Modeling and Flow Simulation for Low-Temperature CO2 Injection
Authors: Pan Huanquan , Chen Yuguang , Sheffield Jonathan , Yih-Bor Chang , Zhou Dengen
Published: October 2014

CO2 injection into an oil reservoir at low temperatures (less than 120 °F) can form three hydrocarbon phases, i.e. a vapor phase, an oil-rich liquid and a CO2-rich liquid phase. Most available reservoir simulators cannot handle three-hydrocarbon-phase flash, and the use of two-phase flash may cause significant numerical instability. The issue has been recognized in the industry for a long time. Studies to include three-hydrocarbon-phase flash in compositional simulations exist in the literature. However, this approach results in substantial increases of model complexity and computational cost, thus it may not be realistic for practical applications (at least for now). In this work, we propose a new PVT modeling procedure to eliminate the three-hydrocarbon-phase region for reservoir fluid/CO2 mixtures at low temperatures, and study its implication on flow simulation. In our method, the acentric factors of pseudo-components are adjusted to eliminate the three-hydrocarbon-phase region, which was not considered in any of the previous studies. Then, the experimental data for reservoir fluid PVT, CO2 swelling test, and MMP are also matched by further adjusting binary interaction coefficients, volume shift parameters and critical volumes of the pseudo-components. The procedure is applicable for cases with relatively small three-phase regions (e.g., some fields in west Texas), and can be applied with any PVT simulation software, and conventional two-hydrocarbon-phase simulators. The method is considered for two sector models from oil fields in west Texas, with fine-scale (more than 600,000 grid blocks) and up-scaled models. Compared to the standard characterization, in which the three-hydrocarbon phases exist, the new fluid model significantly improves the stability of flow simulation, demonstrating the robustness and efficiency of the new procedure. The method can be viewed as a practical approximation to field-scale simulations of the CO2 injection at low temperatures.
New Analytical Method to Calculate Matrix- and Fluid-Corrected Total Porosity in Organic Shale
Authors: Ortega(ConocoPhillips) Edwin , Torres-Verdín Carlos
Published: October 2014

Estimation of total porosity from neutron and density porosity logs in organic shale (source rock) is challenging because these logs are substantially affected by fluid and matrix-composition effects. Conventional interpretation of neutron and density porosity logs often includes corrections for shale concentration in which the main objective is to improve the calculation of non-shale porosity in hydrocarbon-bearing zones. Neutron and density porosity readings across shale zones are typically averaged using the root-mean-square (RMS) method.

We introduce a new and simple analytical expression for total porosity that effectively separates both matrix and fluid effects on neutron and density porosity logs. The expression stems from a new nonlinear mixing law for neutron migration length that is coupled with the linear density mixing law to calculate total porosity and fluid density. The method is applied in two sequential steps: first, separate corrections for only matrix effects are implemented to enhance the neutron-density crossover for qualitative interpretation of fluid type. Next, the coupled equation is used to estimate fluid density and actual porosity devoid of matrix and fluid effects. Calculated porosity and fluid density can be further used to calculate water saturation from density logs. One remarkable feature of this method is the ease with which it can be applied to obtain accurate and reliable results. Application of the method only requires knowledge of single-component nuclear properties and mineral volumetric concentrations. Nuclear properties can be obtained from a set of charts for multiple fluid types and minerals provided in this paper, while mineral concentrations can be calculated based on available triple combo logs or gamma-ray spectroscopy logs.

Two synthetic and four field examples (two conventional and two shale-gas reservoirs) are used to test the method. Firstly, we describe an application in a conventional siliciclastic sedimentary sequence where only shale concentration calculated from gamma-ray logs is required to improve the estimation of porosity in shaly sections. Second, we document several applications in which gamma-ray spectroscopy logs are used together with a reliable hypothesis for clay type to define mineral properties. Results compare well to NMR and core measurements, and the new method outperforms the conventional RMS procedure, especially in the cases of gas-bearing, low-porosity organic shale. The new analytical method can be readily implemented on an Excel spreadsheet and requires minimal adjustments for its implementation.
Natural Fractures in Unconventional Shale Reservoirs in US and their Roles in Well Completion Design and Improving Hydraulic Fracturing Stimulation Efficiency and Production
Authors: Li Bingjian
Published: October 2014

Most of the shale reservoirs in US land are naturally fractured. The fracture intensity and types vary from one shale to another. Even within the same shale in the same field, the heterogeneity of fracture intensity can be often expected to be high in a horizontal well. The current popular geometrical completion design can potentially ignore the existence of natural fractures. Hence, maximizing stimulation efficiency without understanding existing natural fractures can be a challenge. In this paper, study was made of the majority of the published case studies related to natural fractures in the US shales in the last 20 years. The evidence of natural fractures from either outcrops or subsurface data, i.e. core, borehole images, or other data is summarized for each studied shale. The latest studies show that the hydraulic fracture propagation can be strongly influenced by existing natural fractures regardless of whether they are open or closed. The roles of existing fractures in the shales include: 1) providing enhanced reservoir permeability for improved productivity if they are open and effectively connected by hydraulic fractures; 2) promoting much better fracturing network complexity regardless of whether they are open or closed prior to the stimulation; 3) giving possible negative impact sometimes, i.e. high water cut, if they are connected with wet zones below or above the reservoirs. It can be concluded that engineered completion designs that employ accurate knowledge of natural fracture data, in-situ stresses, and other reservoir and completion quality indicators as inputs can provide opportunities for enhancing stimulation efficiency and fracturing network complexity. This in turn can lead to better connectivity to a larger reservoir volume and access to more drainage area in the shales.

Introduction

The US shale gas story actually featured natural fractures. William Hart, a local gunsmith, drilled the first commercial natural shale gas well in US in Fredonia, Chautauqua County, NY in 1821, in shallow, low-pressure rock with fractures[1] [2]. The well was first dug to a depth of 27ft in a shale which outcropped in the area, then later drilled to a depth of 70ft using 1.5 inch diameter borehole. The produced gas was piped to an innkeeper on a stagecoach route[1]. Then the well was produced without any stimulation for 37 years until 1858 when it supplied enough natural gas for a grist mill and for lighting in four shops. It was a combination of the idea from Mr. Hart to drill the well and the presence of the natural fractures in the gas shale that made the 1st commercial shale gas discovery possible in shale gas history.
Experimental and Analytical Core and Geomechanical Data Analysis of a Tight Oil Carbonate Formation
Authors: Islam Arshad , Ziarani Ali S. , Cui Albert , Ehlers Silas , Schneider Brian
Published: October 2014

Unconventional resources around the world and particularly in North America have been revitalized as a result of advancements in hydraulic fracturing and horizontal wellbore technology. This has created a new wave of hydrocarbon exploration, exploitation and development in most of the tight hydrocarbon plays in western Canada. The multidisciplinary (geochemistry, geomechanics and geophysics) approach and the use of nanotechnology in the petroleum industry have not only helped us to improve our knowledge and understanding of these tight and complex reservoirs and their associated systems, but have also resulted in an upsurge of hydrocarbon recovery.

This study focuses on the results of several analyses performed on different core samples from the Swan Hills Formation, which is predominantly a calcium carbonate oil reservoir in the Western Canadian Sedimentary Basin. Routine and special core analyses of the core plugs were conducted to determine reservoir properties, including bulk and skeleton density, porosity by helium pycnometry, and pore size distribution by mercury injection capillary method (MICP). Stress-dependent permeability of the rock (matrix) was measured using the pulse decay permeability method. Triaxial compression tests were also conducted to determine the Young's modulus and Poisson's ratio, compressive strength, and residual strength after peak failure. Linear Mohr–Coulomb failure envelopes (cohesion and friction angle) were also constructed for the intact rock and the rock after failure. Furthermore, short-term and long-term conductivity of acid etched fractures were measured.

Empirical and theoretical correlations were used to model short- and long-term stress-dependent acid fracture conductivity. Nierode-Kruk's model was found to best fit the laboratory data among all models. Constants in Nierode-Kruk's model that depend on rock embedment strength and dissolved rock equivalent conductivity are reported. Effects of different acid concentrations on permeability and conductivity were discussed in detail. Creep testing was performed to determine time-dependent deformation of samples under confining stress. It was found that creep strain is dominated by primary creep stage. Time-dependent creep deformation is minimal for tested samples under various confining pressures. Mineralogy, rock fabric and wormhole growth were investigated using X-Ray Diffraction (XRD), Scanning Electron Microscope (SEM) and Computed Tomography (CT) scanning techniques.
Practical Considerations for Forecasting Production Data in Unconventional Reservoirs — Variable Pressure Drop Case
Authors: Collins Patrick , Ilk Dilhan , Blasingame Thomas Alwin
Published: October 2014

The premise of this work is the development, validation, and application of a methodology to forecast production data in unconventional reservoirs where variable rate and pressure drop producing conditions are typically observed. In unvonentional reservoirs, it is not common practice to maintain or even arrive quickly upon a constant flowing bottomhole pressure which is the primary assumption for the application of traditional time-rate decline curve analysis. As a result the application of traditional time-rate relations to these cases yields misleading results (i.e., EUR values) at best.

Our methodology involves the application of the rigorous convolution/superposition theory with the pressure drop normalized "empirical" rate decline relations as the "well/reservoir" model and the "measured/calculated" pressure drop data. Diagnostic plots of the loss ratio and the loss ratio derivative, or the so called "qDb" plots, are utilized to minimize the non-uniqueness inherent in the history matching process by providing guidance in the selection of rate decline model parameters. Following the selection of model parameters, the normalized rate decline relations are superposed with pressure (or pseudopressure) drop data to achieve a history match and, correspondingly, a production forecast.

Validation and application of the methodology is demonstrated using a variety of synthtic data generated to closely represent common operational practices in tight/shale oil and gas plays. A special emphasis is placed on handling non-linearities and performing sensitivities to account for future drawdown management. We show that the methodology effectively removes pressure variations from the rate history for each of the synthetic examples presented. We present our results using a variety of diagnostic and forecasting plots and both the magnitude of the EUR and the shape of the production profile for all cases.

Introduction

Decline curve analysis (DCA), or the extrapolation of only "time-rate" production data into the future, is one of the most commonly used techniques in the petroleum industry to estimate ultimate recovery (EUR) for producing wells. Essentially decline curve analysis refers to the calibration of a time-rate model, or decline curve, to a single well (or multiple wells) and extrapolating production to an abandonment limit to yield an estimate of ultimate recovery.

he simplicity of the method along with the fact that production from conventional reservoirs honors most of the underlying assumptions have led to Arps' hyperbolic and exponential decline curve relations becoming the industry standard for production forecasts (Arps 1945). Johnson and Bollens (1927) laid the foundation for the exponential and hyperbolic relations when they introduced the loss ratio and the derivative of the loss ratio which are given below.
Environmental Risk and Well Integrity of Plugged and Abandoned Wells
Authors: King George E. , Valencia Randy L.
Published: October 2014

This paper is the third in a series of environmental risk assessments covering hydraulic fracturing (SPE 152596) and well construction (SPE 166142). Risk assessment and well failure from SPE literature and governmental agencies have been used to construct a detailed but non-company associated study of plug and abandonment (P&A) objectives, problems, best practices, application details and methods. The objective is to identify technology improvements as well as potential or proven problem areas. Technology gaps will be related where they are identified by either problem reports or failures.

Case histories have been captured that illustrate a variety of abandonment reasons and approaches in plug setting, isolation and testing/monitoring methods. The study well groupings are divided by age and era or vintage of abandonment to examine the worth of technologies in force at the time of abandonment. Well age, well type and general geographic influences are presented with notation of specific problems and conditions that challenged effective isolation.

Special attention will be paid to cases of failed isolation as cited by the governmental inspection and/or governing body as well as repair methods that restore integrity. Attention will also be given to problems encountered in older wells. Lessons gleaned from this study will be of value to well construction and operational maintenance with consideration paid to well type, geological hazards, production history and durability of the isolation seal.
Modeling the Effects of Anomalous Electromagnetic Diffusion on Induction Logs: The Next Step in Mapping Natural Fracture Corridors
Authors: Elliott Marcus , Everett Mark E. , Heidari Zoya
Published: October 2014

Fracture detection and characterization are challenging aspects of completion plans for unconventional tight carbonate and shale reservoirs. Current industry methods, such as high resolution resistivity imaging, mitigate uncertainties in fracture characterization, but are not cost effective or always available. Conventional well logs (e.g., induction logs) can be better solutions for the industry for reliable fracture characterization. However, these measurements do not provide significant sensitivity to fracture location and geometry. An improved evaluation of thickness and near-wellbore geometry of induced fractures using conventional well logging tools could significantly enhance operational decisions and increase production during field development.

We propose the use of surface gas readings and downhole measurements in combination with numerical simulations of electromagnetic induction log responses to define and high-grade natural fracture corridors. We performed numerical simulations to model the effects of hydraulic fractures on induction log response, within the fractured zones. These simulations consisted of placing resistive fractures, with variable parameters, inside a layered formation, and modeling the apparent resistivity using an induction logging simulator. The fractured zones were represented using a geologic roughening parameter, β, while the simulator is based on the finite element method. The simulator, Seatem, solves the diffusive Maxwell equations, and plots the resulting apparent resistivity distributions within an unstructured tetrahedral mesh. This provides us with a good understanding of how the targeted zone interacts with different stimulation factors.

We successfully performed numerical simulations along a multi-zoned reservoir interval for three synthetic cases: a sandstone formation, a carbonate formation, and an organic shale formation. We quantified the effects of hydraulic fracturing on induction logs and optimized placement of fracture treatments on synthetic cases. The results of this paper indicate fractured zones with beta values larger than 0.3, viable for fracture corridor depletion and geologic targeting, can be identified from induction log responses.
60 Years of Multi-Fractured Vertical, Deviated and Horizontal Wells: What Have We Learned?
Authors: King George E.
Published: October 2014

Multiple fracture placements in single wells have a sixty year history with first applications soon after hydraulic fracturing was patented. Fracturing technology has been applied to offshore deviated wells, sand control wells, tight gas, coal, chalks, shales and conglomerates in turn as "conventional" reservoir limits were reached and each "new unconventional" reservoir was encountered. As fracturing technology was adapted to make an "unconventional" reservoir into a conventional reservoir, the adaptations and evolutions needed became part of the technology tool box waiting for the next challenge. Each innovation improved and stretched the reach of completions and production engineering as new findings were incorporated to monitor, model, optimize and extend the ranges of fracturing use for high and low temperatures, high stress formations and a variety of other challenges.

This review looks at the development of multi-fractured wells from its first application in vertical wells where one well could now do the task of three wells, to the first modern application of highly multi-fractured horizontal wells used in chalks, shales and tight oil and gas reservoirs. The technical focus is on the learning procession covering details of casing wear, cyclic pressure application, isolation mechanisms, perforation placement, well spacing and fracture spacing.

The technical literature and field learnings have both been searched for applicable information with a surprising variety of engineering application details brought forth that are useful in optimizing a single well or a whole development.
Multivariate Control for Managed Pressure Drilling Systems Using High Speed Telemetry
Authors: Shishavan Reza Asgharzadeh , Hubbell Casey , Perez Hector D. , Hedengren John D. , Pixton David S. , Pink Anthony P.
Published: October 2014

With the recent advance in high speed data communication offered by wired drill pipe (WDP) telemetry, it is now possible to design automated control systems that directly utilize downhole data (e.g. pressure) to optimize drilling procedures. This research couples drilling hydraulics, rate of penetration (ROP), and rotational speed (RPM) control into a single controller for managed pressure drilling systems. This novel multivariate controller improves drilling performance during normal drilling operations and enhances safety during abnormal drilling conditions such as unwanted gas influx situations.

New advances in drilling automation have made the closed loop control of downhole weight on bit (WOB) and drill string rotational speed (RPM) possible. This study uses two feedback controllers that control the downhole WOB and RPM using surface data. A multivariate nonlinear model predictive controller (NMPC) uses downhole and surface measurements to simultaneously regulate the bottom hole assembly (BHA) pressure and maximize the ROP. For this purpose, NMPC provides the necessary set points for the WOB and RPM feedback controllers as well as manipulates the choke valve opening and pump flow rates. Controller performance is enhanced via a nonlinear estimator that works continuously online with the NMPC and provides the necessary estimated parameter values (i.e. annulus density, friction factor, and gas influx) for precise and efficient drilling control.

The designed NMPC controller has a multi-priority approach which is described in the following three scenarios: (1) during unexpected gas influx, the NMPC gives priority to BHA pressure control and attenuates the influx effectively via a novel kick attenuation method that switches the control objective from BHA pressure to choke valve pressure; (2) during connection procedures when adding a new stand, ROP is stopped and the NMPC focuses on maintaining the BHA pressure constant; (3) during normal drilling operation, which involves changes in the rock formation and differential pressures, NMPC gives priority to ROP maximization while maintaining RPM, WOB, and BHA pressure within specified bounds.

Preliminary results suggest that this multivariate controller for ROP and BHA pressure control will decrease drilling costs, reduce operator workload, and minimize risk significantly. Specific improvements in drilling performance include higher ROP, effective kick attenuation, and more uniform cuttings. The use of a multivariate NMPC allows for better ROP optimization and BHA pressure control than would be possible with the use of two independent controllers. These benefits are demonstrated across the three scenarios mentioned above. This technology has potential to deliver significant performance improvements during managed pressure drilling and further the development of auto driller systems.
Petroleum Senior Students Specialize in Operations or Reservoir Engineering
Authors: Heinze Lloyd R. , Watson Marshall C. , Herd Bob L.
Published: October 2014

The Bob L. Herd Department of Petroleum Engineering at Texas Tech University has significantly revised the curriculum for the senior year. In response to industry, Texas Tech's petroleum industry advisory board, senior exit interviews, and surveys from recent graduates; the faculty have altered the senior course offering. The major concerns expressed centered on providing students with sufficient course work in both Reservoir / Formation Evaluation (RFE) and Drilling / Production Operations (DPO). Adding four additional courses would exceed the reasonable limits of a four year undergraduate BS degree. A 148 hour program would approach conventional MS degrees. The department decided to leverage existing low level master courses to allow seniors to select a RFE or DPO specialty. The goal is more depth and a little less breadth.

During their senior year, students elect to take four RFE or four DPO courses along with the other required senior petroleum courses. This has allowed an interesting dynamic in the two senior semester design sequence. Teams are formed with course background of both RFE and DPO courses. This has also changed the material covered during semesters four, five, and six (sophomore and junior semesters). Students will only have a minimum of coverage in either RFE or DPO courses in semester four-six. During these three semesters, the department significantly ramped up the petroleum material covered. Departments of Geology, Energy Commerce, and Industrial Engineering have provided petroleum related course improvements to further enhance the student outcomes.

The department has completed its first year of the new curriculum, and plans to share the results at the next SPE Annual meeting. These changes have been tracked using ABET methods to assess and improve the program.

The vision was to enhance undergraduate student understanding of the theory and equations taught by building concepts of procedure and construction. Designing procedures for oil field operations and evaluation is key to developing critical thinking. Concepts of largeness of scale of the industry, timing and logistics, and the ability to "critically think" about the reservoirs and fluids; all under conditions that are not observeable in their downhole "native" state are extremely difficult to convey through equations and computer program "black boxes." The faculty and industry advisory board noted a gradual movement of recent graduates to rely on "plug and chug" putting values in equations and computer black boxes prior to determining whether the numbers input are correct or accurate. Students were relying too much on the computer answer without ensuring the values represented a reasonable result. They often didn't question the magnitude or the significant figures (accuracy) of their answers. In addition to understanding magnitude and accuracy, students are taught the uncertainity that petroleum engineers must deal with is a critical distinction of the profession.
Integrated Management Strategy of Flow Assurance for Digital Field
Authors: Zhang He , Li Jun , Khor Siew Hiang
Published: October 2014

Nowadays the oil and gas industry devotes great attention and efforts to unconventional hydrocarbon resources. Production operations on these resources are often challenging due to possible complex risks, and flow reliability can become a key concern upon high intervention costs. Understanding and managing the related risks require detailed multidisciplinary engineering analysis involving accurate fluid characterization and advanced multiphase flow simulations. This practice of ensuring successful and economical flow of hydrocarbons is called Flow Assurance (FA); which alsohas become a substantial consideration in reservoir management.

This paper firstly presents an innovative rating system covering all types of FA problems by Design of Experiments (DoE) and Fuzzy Logic methods respectively. With the emerging digital field technologies, this work can subsequently propose an integrated management workflow on addressing various FA issues. Supported by a case study, this paper demonstrates the importance of this decision-making process in light of the proposed workflow. A remedy for one identified FA problem may result negative side effects for a production system over years, and subsequently decrease the reserves and the project profitability.
A Practical Petrophysical Approach for Brittleness Prediction from Porosity and Sonic Logging in Shale Reservoirs
Authors: Jin Xiaochun , Shah Subhash , Truax Jerome , Roegiers Jean-Claude
Published: October 2014

Brittleness has been used as one of the important descriptors for the characterization of unconventional shale reservoirs. The degree of brittleness in shale reservoirs is determined upon the basis of its mineralogical composition, which can be obtained from mineralogical logging tools (such as ECS™, FLeX™, GEM™, Litho Scanner™), or XRD tests in the laboratory. Generally, measurements of mineralogical brittleness are obtained from physical sources and lead to relatively reliable interpretation results. However, mineralogical logging is expensive and not commonly available in the shale play. Alternatively, brittleness can also be calculated from dynamic Young's modulus and Poisson's ratio, but the absence of shear slowness in some wells restricts its wide application. Internal friction angle based brittleness can give similar interpretation results as the preceding two methods, but its accuracy depends highly on the quality of correlations. It is observed that the curves of the three different brittlenesses demonstrate similar shapes. Therefore, we have attempted to build correlations between mineralogical brittleness and porosity or sonic compressional slowness for typical shale plays (Woodford, Barnett, and Eagle Ford shale), and have proven their validity with the data obtained from wells not included in the development of correlations. Applications of these findings include: (1) enabling the possibility of evaluating brittleness in plays lacking mineralogical and shear sonic loggings, thus reducing the quantity of laboratory testing, (2) inspiring operators to develop in-house correlations of brittleness for shale gas plays, and (3) investigating similar correlations in emerging unconventional oil plays, such as Granite Wash.
Proactive Novel Approach and Design Strategies to Zonal Isolation in a Highly Challenging Deep Water Environment
Authors: Grant Lisa , Japar Nor Janiah , Reagins Deandre , Hale Arthur , Mercado Steven , van den Haak Arno L.M. , Lloyd Russell , Pereira Andre Guilherme
Published: October 2014

In September 2010 a decision was made to expand the current Mars field development with a second 24 slot TLP structure in a water depth of 3000 ft. This new development includes higher pressured deeper pays below the existing brown field Mars pays. The new structure will install wells with multiple casing strings across stacked sand packages that are both depleted and virgin pressured ranging from 10,500 ft to 23,000 ft TVD in depth. This in combination with other challenges such as extremely tight annuli clearances, depletion zones greater than 5000 psi, multiple stacked sands at varying degrees of depletion, and risk of borehole stability failure/ballooning presents a unique set of zonal isolation challenges that requires proactive novel approaches and design strategies. Zonal isolation is a regulatory requirement and a key component of project success in order to secure maximum field recovery and future wellbore utilization within the estimated field life.

Zonal isolation methodology and design does not have a single focus but explores all parameters that affect placement and isolation while not losing focus on striving operational simplicity. This paper discusses the engineering approach to zonal isolation requirements in a highly challenging environment utilizing a step wise methodology with increasing complexity and also elaborates on how this approach led to the identification and ultimately the development of new technologies.

Design methodologies will be discussed as well as resulting technologies identified as a "must haves" for development to ensure maximum probability of zonal isolation success. Technologies discussed will include reverse cementing tools, 50 (+) year seals for stage collars, and connection requirements. Statement of Requirements (SORs), basic tool descriptions, and preliminary results of these developments will also be included. Discussions on why certain placement techniques or approaches were not integrated into the zonal isolation project plan will also be discussed.
Subsea Well Intervention: Recent Developments and Recommendations to Increase Overall Project Returns
Authors: Nelson M. E. , McLeroy P. G.
Published: October 2014

As the subsea industry ages, the number of premature subsea well shut downs are increasing due to insufficient well intervention programs. In the past, subsea well interventions have not been widely used because of a lack of economic feasibility; however, with appropriate project planning, the recent economic climate, and advances in well intervention technology, a greater overall project return can be realized by implementing a proactive well intervention program. While intervention on surface wells is a familiar topic, the benefits and negative consequences of more recent subsea intervention developments, such as riser-less light well intervention, riser-less mud return, and well flow back and testing, are evaluated. These different well intervention methods carry varying amounts of risk with them, with the potential to greatly enhance or diminish well performance and thus affect recoverable hydrocarbons. The risks involved with the different well intervention methods are evaluated and recommendations are made as to which methods are utilized depending on desired return rates and risk aversion levels. Recommendations are made for implementing a successful well intervention program, such as production monitoring, scenario planning, application of a dedicated multi-disciplinary team, cross-organizational collaboration, and logistical improvements. With an effective well intervention program, reservoirs can be further exploited, potentially increasing project return and supplying hydrocarbons to a demanding global market.
Predicting Production Behavior of the Marcellus Shale
Authors: Mashayekhi A. , Belyadi F. , Aminian K. , Ameri S.
Published: October 2014

The long-term production behavior of horizontal wells producing from Marcellus shale due to limited production history has not been well established. As a result a simple method for predicting the long-term production and reserves would be of interest. Several production decline curve analysis models have been proposed specifically for application to unconventional gas reservoirs. However, reliable production predictions cannot be obtained when they are applied to limited production history such as those available from Marcellus shale wells. In this study, the production and completion data from a number of horizontal wells completed in Marcellus shale were collected and used to build a generic model. The model was then in conjunction with a commercial dual porosity numerical model which included the adsorbed gas to simulate long-term production profiles for Marcellus shale horizontal wells with multiple hydraulic fracture stages. The simulated production profiles were then utilized to develop correlations for adjusting the conventional (Arps) decline curve constants obtained to from the limited production history to accurately predict the long-term production performance. The impacts of key formation and fracture properties on the decline curve constants were also investigated. Finally, the correlations were utilized to accurately predict the long-term production rates from a Marcellus shale horizontal well in West Virginia based on the early production history.
Unconventional Reservoir Formation Evaluation Challenges Addressed With Deployment-Optimized Open Hole Logging Solutions
Authors: Hameed A. , Bacciarelli M. , Williams P. J.
Published: October 2014

It is estimated that only one third of the remaining worldwide oil and gas reserves are conventional, the remainder being in unconventional reservoirs whose evaluation requires appropriate measurements delivered in a cost-effective way. In the case of shales and other tight reservoirs, the defining characteristics are low matrix porosity and low or ultra-low permeability which requires artificial stimulation to encourage production. The optimum stimulation strategy for a particular reservoir is strongly dependent on the distribution of organic material, and on the mechanical and geometrical properties of the rock, and the associated stress field. It is essential to quantify these to an appropriate level of certainty, and well logs are the primary source of such data. Until recently the options for acquiring appropriate logs in high angle and horizontal wells have been constrained either by the limited available sensors or tool conveyance methods. However, the introduction of memory capable small diameter specialized tools and multiple innovative conveyance options has changed the cost-benefit balance for the better. This paper reviews the current status of open hole log measurements with full spectrum conveyance options, and how they impact the evaluation of these challenging reservoirs.
An Integrated Reservoir Model for Unconventional Resources, Coupling Pressure Dependent Phenomena
Authors: Eshkalak Mohammad O. , Aybar Umut , Sepehrnoori Kamy
Published: October 2014

An integrated unconventional reservoir model that accounts for known mechanisms and nonlinearities affecting modeling of hydraulically fractured wells is developed. In general, modeling and simulation of multi-fractured reservoirs are highly challenging due to the complexity attributed to the flow in this very low permeability and dense structured rock. Pressure- dependent phenomena in reservoir modeling are considered as combined hydraulic and natural fracture conductivity losses, desorption, Klinkenberg gas slippage effect and non-Darcy flow. Integrating these phenomena and analyzing the importance of each parameter in a reservoir model are essential.

The proposed model includes three zones, Rock Matrix (I), Induced-Fracture (II) and Hydraulic Fracture (III) that are defined with different characteristics. Pressure dependent permeability is considered for zone II and III, with an exponential relationship between permeability and reservoir pressure. Governing equations of gas flow are non-linear partial differential equations, for all three zones, due to incorporated pressure-dependent phenomena that are solved using the finite difference method. A synthetic case is defined in order to investigate the effect of each individual phenomenon on long-term production. Moreover, a history matching process with Marcellus Shale field production data is performed in order to obtain the most uncertain parameters in the model.

Results showed that combined effect of permeability losses of hydraulic and induced-fracture zones results in 15 percent gas production drop in 30 years. Also, it is observed that Klinkenberg effect and non-Darcy flow have insignificant effect on the modeling of shale gas reservoirs, whereas desorption has great contribution on long-term production. It is concluded that the minimum ingredients for an accurate shale reservoir modeling are considering gas desorption phenomena alongside with pressure-dependent permeability for the hydraulic and induced-fractures network. Our simple reservoir modeling approach helps in understanding complex behavior of flow mechanisms in shale plays. Also, this integrated model can be used during optimization of key factors in hydraulic fracturing process and fracture characterization by history matching of production.
Scaling from an Unexpected Source: Proppants
Authors: Luo Hongyu
Published: October 2014

Scales such as aluminum silicates are commonly believed to come from reservoir rocks such as shale and/or their interaction with injected chemicals from EOR (enhanced oil recovery) methods. In hydraulic fractured wells, scales could be a major source of damage to fracture conductivity, which is usually less than 5% of their desired value by fracturing design. Despite much research on conductivity loss, few efforts have been directed at proppants, the number one material by quantity (except for water) used in fracturing operations.

In this research, a brief review is conducted on how proppants might be an active agent in scale-generating reactions. Using a ceramic proppant sample from the Bakken shale oil field as an example, a new method is proposed for characterizing proppant strength and interaction with fracturing fluids, rock, and formation and production fluids under realistic down-hole conditions. It was found that certain ceramic proppants widely used in the Bakken field are vulnerable in weakly acidic fluids (i.e. pH=4). Temperature increases expedite the proppant weakening process. Estimated conductivity loss could be ~50% compared with that treated at neutral pH. This is alarming because many wells produce sweet (carbon dioxide CO2) and/or sour (hydrogen sulfite H2S) gas along with production fluids. Common scale inhibitors such as phosphonate-based acids and polycarboxylic acids (PAA) could also lower the pH of fluids in propped fractures to 3~4, break the ceramic proppant and generate fines and scales.

The first lesson learned is that proppants could be a source of scale. Proppants, especially ceramic ones, should be treated as a chemical and potential source of scale when implementing designs for hydraulic fracturing or gravel packing. Not only will poor quality proppants crush easily, but also they may generate migrating scales, a double inhibition for flow assurance. Extreme care should be exercised when choosing proppants for sour wells. Tighter specification on acid resistance of proppants is proposed. Field quality control and scale management in fractured wells will also be discussed.
Effect of Saturation Dependent Capillary Pressure on Production in Tight Rocks and Shales: A Compositionally-Extended Black Oil Formulation
Authors: Nojabaei B. , Siripatrachai N. , Johns R. T. , Ertekin T.
Published: October 2014

Pore sizes are typically on the order of nanometers for many shale and tight rock oil reservoirs. Such small pores can affect the phase behavior of in situ oil and gas owing to large capillary pressure. Current simulation practice is to alter the unconfined black-oil data for a fixed mean pore size to generate confined black-oil data with a depressed bubble-point pressure. This approach ignores compositional effects on interfacial tension and the impact of pore-size distribution (PSD) with variable phase saturations on capillary pressure and phase behavior.

In this paper, we develop a compositionally-extended black-oil model where we solve the compositional equations (gas, oil, and water components) directly so that black-oil data are a function of gas content in the oleic phase and gas-oil capillary pressure. The principle unknowns in the variable bubble-point fully-implicit formulation are oil pressure, overall gas composition, and water saturation. Flash calculations in the model are noniterative and are based on K-values calculated explicitly from the black-oil data. The advantage of solving the black-oil model using the compositional equations is to increase robustness of the simulations owing to a variable bubble-point pressure that is a function of two parameters; gas content and capillary pressure. Leverett J-functions measured for the Bakken reservoir are used to establish the effective pore size-Pc-saturation relationship, where the effective pore size depends on gas saturation. The input fluid data to the simulator, e.g. interfacial tension (IFT), phase densities and viscosities, are pre-calculated as functions of pressure from the Peng-Robinson equation of state (PREOS) for three fixed pore sizes. During the simulation, at any pressure and saturation, fluid properties are calculated at the effective pore radius by using linear interpolation between these three data sets. In the current simulator, the reservoir permeability is enhanced to allow for opening of the fracture network by hydraulic fractures. We compare the results of the compositionally-extended black oil model with those of a fully-implicit eight-component compositional model that we have also developed. The results for the Bakken reservoir show that including PSD in the model can increase estimated recoveries by nearly 10%. We also examine the sensitivities of production to various parameters, such as wettability and critical gas saturation.
Identifying the Ideal Stimulation Design via Quantitative Multivariate Analysis – Second Bone Springs Sand, New Mexico
Authors: Rice Ryan
Published: October 2014

One of the major challenges associated with economic exploitation of unconventional hydrocarbon accumulations in shale resource development is determining the optimal stimulation design. This work employs quantitative multivariate analysis to determine the efficacy and efficiency of different hydraulic fracturing designs. If the analysis is done correctly, it allows for accelerated delineation of unconventional plays, minimizes excessively long learning curves, and increases well productivity. It is important to recognize that previously published work, such as SPE 152531, SPE 163852, and SPE 1355223, propose alternative methods for identifying optimal completion designs. However, these methods require access to expensive and/or complex neural networking and proxy modeling software, as well as an advanced statistics background. Alternatively, this research proposes a simple, novel, and effective approach for ascertaining the most ideal completion design using the most basic software packages and statistical analysis. Most importantly, this method focuses not on finding statistical averages for each stimulation variable but instead finding inherent trends in real data.
Fracture Conductivity Damage by Water in Shale Formations
Authors: Zhang Junjing
Published: October 2014

Multi-stage hydraulic fracturing is the key to the success of many shale gas and shale oil reservoirs. The main objective of hydraulic fracturing in shale is to create fracture networks with sufficient fracture conductivity. Due to the variation in shale mineralogical and mechanical properties, mechanisms of fracture conductivity damage in shale formations are complicated. Standard fracture conductivity measurement procedures were developed for high concentration propped fractures and need to be modified to measure the conductivity of the low concentration proppant packs. Water-based fracturing fluids can interact with the clay minerals in shale and eventually impact shale fracture conductivity. All these challenges require more studies to elevate our understanding of realistic fracture conductivity in shale formations.

The aims of this work were to design an experimental framework to measure fracture conductivity created by low concentration proppants and to investigate the mechanisms of conductivity damage by water. We first presented the laboratory procedures and experimental design that can accurately measure fracture conductivity of shale fractures at low concentrations of proppants. Then we measured the undamaged shale fracture conductivity by dry nitrogen. Water with similar flowback water compositions was injected to simulate the damage process followed by the second gas flow to measure the recovered fracture conductivity after the water damage.

From this study, we find that laboratory procedures developed in this study can be utilized to reproducibly measure shale fracture conductivity by both gas and liquid. The conductivity measurement of propped fractures by small size proppants at low concentrations requires strict control on gas flow bypassing the fracture both parallel and perpendicular to the fracture length direction. Shale fracture surface softening is identified as the dominant cause for the significant conductivity reduction after water flow.
Comparative histology of testes of brown (Salmo trutta m. Fario) and California (Oncorhynchus mykiss) trout during the spawning period
Authors: Mlaco N. , Katica A. , Pilic S.
Published: October 2014

The testes of fish are paired organs, of a variable shape in different
species of fish. Their structure in the salmonid species is lobular. With the
histological assays, we established that the lobes were separated by the
connective tissue septa, which, given the intensity of spermatogenesis in the
studied groups of fish (Salmo trutta m. Fario; Oncorhynchus mykiss)
sporadically disappear, in fact, they break. In the space between the lobes
there are also cross-sections of blood vessels with visible erythrocytes.
During the spermatogenesis, in the interstitium there are clearly observable
interstitial endocrine (Leydig) cells that excrete steroid hormones. The
intensity of the spermatogenesis in the studied fish varies, which is
concluded on the basis of the presence of the spermatogenesis cells. In
nature, the reproductive cycle in fish is mostly based on an annual cycle,
and that is why different stages of reproduction take place at a different
temperature and during a different photoperiod. Hence, regardless of the same
time period, the spawning time in November, different types of breeding, and
finally salmon farming, point to the very important factors that influence
reproduction - diet and microclimatic conditions.