bluuebunny/crossref_metadata_2025 huggingface dataset:
Economic Optimization of Horizontal Well Completions in Unconventional Reservoirs
Authors: Barree R. D. , Cox S. A. , Miskimins J. L. , Gilbert J. V. , Conway M. W.
Published: June 2014

Extrapolation of conventional paradigms to unconventional reservoirs can lead to disappointment and poor performance. Careful analysis of the reservoir and application of the correct stimulation design is critical when dealing with marginally economic developments. This includes adequate characterization of the reservoir and an understanding of the factors that control flow capacity and deliverability.

One of the biggest practical problems with unconventional stimulation design optimization is estimating post-fracture rate, production decline and ultimate recovery. Without a realistic prediction of the decline resulting from a given completion it is impossible to assign value to one design over another and equally impossible to optimize the treatment for whichever goal is sought, either acceleration of recovery or increase in reserves.

It is often the first - inadequate reservoir characterization - that leads to the second - unrealistic post-treatment predictions. For instance, assuming core-derived permeability fully represents the reservoir's total flow capacity or that stimulated reservoir volumes represent the effective producing volumes, can lead to incorrect diagnosis of the reservoir capability and consequently, lead to an inefficient treatment design.

This paper presents methods for production forecasting that give reasonable post-treatment predictions that have been found useful for economic planning. The proposed methodology, backed by field observations and laboratory work, provides an economically viable plan for optimizing lateral length, fracture spacing, and treatment design. The methodology focuses on the post simulation effective reservoir volume. Results show that increasing apparent fracture length rarely impacts long term recovery. Likewise, adding more fractures within the same reservoir volume may increase early time production rate (IP) and decline rate, without contacting more reservoir volume or adding to long term recovery. Such practices lead to acceleration of reserve recovery, which has economic value and should be considered in the design process, but does not increase the well's ultimate recovery once a sufficient number of fractures are in place. The economically preferred completion designs may be more driven by the net present value derived in the first five years of production rather than focusing on 20-50 year EUR's. This period represents most of the useful economic life of the well, can be estimated more accurately from early performance and therefore is a good benchmark for completion optimization.
A Fully Coupled Geomechanics and Fluid Flow Model for Proppant Pack Failure and Fracture Conductivity Damage Analysis
Authors: Han Jiahang , Wang John Yilin , Puri Virendra
Published: June 2014

One reason of observed reductions in the conductivity of hydraulic fracture is failure of proppant pack under the stresses. Proppant deformation, crushing or embedment can decrease the fracture width and conductivity. In this paper, continuity equation and momentum balance equation were fully coupled to simulate the transient phenomena involving fluid flow through a deformable porous proppant pack. Porous media displacement, water pressure, and gas pressure were derived as primary unknowns. The governing equation was discretized using the finite element method and solved numerically. In this model, proppant pack and formation rocks were treated as two different types of continuous porous mediums (Biot type). Proppant deformation, crushing, and embedment could be identified through the geomechanical model, while the damage effects on gas/oil production would be studied through the fluid flow model. Analysis of proppant deformation and crushing was based on the proppant pack stress-strain behavior. The displacement on fracture-formation interface represented the proppant embedment. Mohr-Coulomb failure was used as the criteria for proppant crushing. Effects of proppant damage were evaluated on proppant pack porosity and permeability. The model can be applied in all the hydraulically fractured reservoir with proper inputs. In this paper, we used fractured tight sand gas reservoir as a study case. The pressure distribution as well as proppant pack deformation were illustrated in the paper. Proppant pack mechanical behavior was found to be sensitive to the fluid flow pressure and proppants near wellbore was under higher possibility of being crushed.
A Statistical Study of Proppant Type vs. Well Performance in the Bakken Central Basin
Authors: Flowers J. R. , Guetta D. R. , Stephenson C. J. , Jeremie P. , d'Arco N.
Published: June 2014

Every new oil and gas development goes through a typical growth cycle starting with the discovery well. A large part of that growth process is optimizing the well completion techniques ad this tends to be the most difficult process to optimize due to the difficulty in measuring the success or failure of these changes. When modifications are made in the drilling process results can be measured almost immediately while changes in well completions can take months or years to evaluate and require the analysis of many variables.

Determining the optimal fracturing treatment in North Dakota's Bakken has been a widely discussed topic in recent years. Data from field trials, which focus on a few dozen wells, provide broadly contradicting claims regarding the ideal proppant that should be used in the fracture treatment. This lack of agreement results in a disparity between treatment practices in otherwise geographically close wells that are completed in similar formations. This paper will utilize a statistically significant volume of publicly available, operator-originated data, with the intent of making a data-driven determination regarding the optimal treatment.

This paper combines production data from the North Dakota Industrial Commission (NDIC) and completion reports from the publicly accessible FracFocus 2.0 database which contains over 2,900 well records from the Bakken. The statistical analysis of this data reveals a correlation between the proppant type used and the well performance in the Bakken Formation.

This data was pared down to concentrate on the Central Basin which consists of McKenzie and Williams counties. Comparing the long term performance of 205 wells from this area indicates a clear advantage of ceramic proppants over other proppant types. The results of this analysis show that ceramic proppants result in a slower production decline which leads to significant increases (20-40%) in 6 month and 1 year cumulative production. This increase in well production more than offsets any additional completion cost resulting in an improved ROI.
Limited Height Growth and Reduced Opening of Hydraulic Fractures due to Fracture Offsets: An XFEM Application
Authors: Abbas Safdar , Gordeliy Elizaveta , Peirce Anthony , Lecampion Brice , Chuprakov Dimitry , Prioul Romain
Published: June 2014

Hydraulic fracture propagation through a layered medium often exhibits a complex fracture path due to lateral shifting of the fracture path after passing through an interface. The existence of these offsets in the fracture path has been confirmed by mapping of mined fractures and by laboratory experiments. In addition to the stress contrast and material contrast, these offsets act as another mechanism for fracture-height containment. In order to investigate fracture height growth problem, we have considered a case of plane-strain fractures propagating from an injection point and propagating in a predetermined path. Fracture offsets of a given length and angle are prescribed within the predetermined path. In this way, we parametrize the problem of fracture offsets in order to quantify their effects on the fracture height growth and fracture opening reduction at the fracture offset (pinching effect). This is done while keeping a hydrostatic state of confining stresses in order to observe only the geometric effect of the fracture offset. We use a recently developed hydraulic fracturing code based on the eXtended Finite Element Method (XFEM). This code solves the fluid flow in the fracture and the elastic response of the fracture in a fully coupled manner solving for the fracture velocity using the complete hydraulic fracture tip asymptotics.

For different combinations of independent parameters (i.e., formation moduli, far-field stresses, fluid injection rate, ratio of offset length to the length of the straight fracture and the offset angles) we investigate the effect on the fracture height growth and the reduction in fracture opening at the fracture offset. A detailed parametric study shows that while each parameter affects the fracture height containment, the fracture opening reduction is dominated by the fracture offset angle which is a geometric effect of the fracture offsets. This has a profound effect on the proppant bridging at the fracture offset.
On the Mechanisms of Shale Microfracture Propagation
Authors: Padin Anton , Tutuncu Azra N. , Sonnenberg Steve
Published: June 2014

Economical production rates in shale reservoirs are achieved solely by hydraulic fracturing the pay zones on horizontal wells with multiple stages, thus this technique is an essential tool for the development of enormous reserves of oil and gas in the United States. However, the processes that dominate hydraulic fracturing in shale reservoirs are poorly understood, and the variability of the properties from one shale play to another makes this learning process intricate. In this paper, we investigate the evidence of microfracture propagation on ductile shales and the key factors that constrain its slippage. First of all, we present evidence from the study of two reservoirs, the Eagle Ford formation in South Texas and the Vaca Muerta formation in Argentina. Secondly, we analyze the key parameters that affect flow through microfractures in organic-rich mudstones. We identify the key variables used to characterize these reservoirs through integration of geomechanics laboratory experiments with microseismic monitoring, mineralogy, organic carbon content, fabric, log, core, geological and field data analysis. Our ultimate goal is to identify the main parameters that influence fracture flow from very tight shales with the ultimate goal of optimizing the completion design in these complex formations. With this objective in mind, we examine the relatively slow slip process of tensile fracture growth in ductile, high clay and organic content shales, which results in the reactivation of preexisting horizontal fractures, producing aseismic energy. We then compare this mechanism against the fast shearing deformation that generates microseismicity in brittle shales. By observing the differences between the macro-scale (microseismic, anisotropy of the acoustic waves, geomechanics experiments), the meso-scale (fabric-thin section) and the micro- and nano-scales (clay particles) we suggest that the mechanisms of fracturing on ductile versus brittle rock are seen at any scale; that the anisotropy of the fabric of the rock within the interface between clay and non-clay minerals that differ in size and strength, the anisotropy of the horizontal stresses, the overpressure conditions, the friction angle of kerogen, the orientation of the pre-existing microfracture network with respect to the current stress state and –to a lesser extent- the elastic moduli of the rock matrix, are the most significant parameters that dominate microfracture propagation mechanisms on organically-rich rocks. The systematic integration of data from two analogous shale reservoirs and its comparison against existing theories on the mechanisms of fracture propagation has the benefit of approaching the process of fracturing from a predictive perspective, with potential benefits on stimulation optimization.
Application of Multivariate Statistical Modeling and Geographic Information Systems Pattern-Recognition Analysis to Production Results in the Eagle Ford Formation of South Texas
Authors: LaFollette Randy F. , Izadi Ghazal , Zhong Ming
Published: June 2014

As of this date, approximately 5,000 horizontal Eagle Ford wells have been completed in South Texas. Still, geologists and engineers question whether their companies are using the most appropriate operating practices. Side-by-side case studies may show value or not, given the challenge of small sample size and hidden influences on outcome. Multivariate statistical analysis of larger data sets offers sound interpretation across larger geographic areas, with the caveat that correlations need to be scaled to local conditions. The purpose of this paper is to apply multivariate statistical modeling in conjunction with Geographic Information Systems (GIS) pattern recognition work to the Eagle Ford.

The investigation began by acquiring Eagle Ford data using both proprietary and public information. The different data sets were loaded into a common database and put through quality control sanity checks. Production proxies, such as maximum oil rate in the first 12 producing months and normalized 12 month cumulative production, were selected and merged with the other data. Final data sets were then subjected to analysis in both an open-source multivariate statistical analysis and visualization code and a commercial Geographic Information Systems (GIS) application.

Similar to other studies in unconventional reservoirs, integration of the two analysis and interpretation methods highlighted the importance of using well location as a proxy for reservoir quality when working with data sets that lack such measurements. The use of multivariate statistical analysis allowed modeling the impact of particular well architecture, completion, and stimulation parameters on the production outcome by integrating out the impact of other variables in the system.

This work is a continuation of the prior work designed to address well optimization in unconventional reservoirs. It is significant in that it takes full advantage of GIS map-based methods and multivariate statistical methods to capitalize on the volume of data available through the public domain.
Impact of Accurate Fractured Reservoir Flow Modeling on Recovery Predictions
Authors: Singh G. , Pencheva G. , Kumar K. , Wick T. , Ganis B. , Wheeler M. F.
Published: June 2014

The design and evaluation of hydraulic fracture modeling is critical for efficient production from tight gas and shale plays. The efficiency of fracturing jobs depends on the interaction between hydraulic (induced) and naturally occurring discrete fractures. We describe a coupled reservoir-fracture flow model which accounts for varying reservoir geometries and complexities including non-planar fractures, faults and barriers. In addition our model is coupled with linear elasticity using iterative coupling to solve a multi-phase Biot system. The approach presented here is in contrast with existing averaging approaches such as dual and discrete-dual porosity models where the effects of fractures are averaged out. We model the fractures and reservoirs explicitly, which allows us to capture the flow details and impact of fractures more accurately. Moreover, accurate modeling of solid deformations necessitates a better estimation of fluid pressure inside fracture, which our flow model provides. We utilize different flow models for the fractures and the reservoir closely capturing physics when needed. A quantitative comparison is made in order to identify situations where a multiphysics flow description is critical to accurate prediction compared to an averaging based approach. We present several numerical tests, including a field scale case study, to illustrate the above features and their impact on recovery predictions.
New Technology Yields Ultra High-Strength Proppant
Authors: Palisch Terry , Wilson Brett , Duenckel Bob
Published: June 2014

Nearly all of the proppant available on the market today can be classified into one of three tiers - sand, resin-coated sand and ceramic. The products contained in these three tiers have served the industry well and have typically covered the broad spectrum of applications required by completions engineers. However, with the development of deeper reservoirs as well as the ongoing look at geothermal and steam-flood applications, there now exists a gap in proppant technology. No conventional proppant can provide the required conductivity at the 20,000 psi closure stresses (and higher) anticipated in the Lower Tertiary formations in the deep Gulf of Mexico. Similarly, no conventional proppant can adequately withstand the harsh chemical conditions in many geothermal and steam-flood applications.

A new proppant has been developed and commercialized to meet these challenges, achieving twice the baseline conductivity of any conventional proppant at these high stresses, and providing additional advantages with increased durability and longevity. This paper will review the step change advancements achieved by this new proppant, including technology improvements in both raw materials and manufacturing process. It will present properties never seen before regarding proppant shape, sizing and strength. Extensive laboratory testing has been completed to demonstrate the superior performance in harsh conditions, and will be presented.

The paper will also present the expected applications for this product, including areas where increased production rates, superior EUR, lower erosivity and reduced equipment wear are a premium. Field applications are beginning as of this writing.

This paper should be beneficial to all engineers and technologists currently working in stress applications greater than 15,000 psi, or other harsh conditions such as steam-flooding and geothermal applications.
A Comparison of the Effectiveness of Various Fracture Fluid Systems Used in Multi-Stage Fractured Horizontal Wells: Montney Formation, Unconventional Gas
Authors: Reynolds M. M. , Bachman R. C. , Peters W. E.
Published: June 2014

Recently, there has been discussion of the need to advance hydraulic fracturing technology from the current ‘operational effectiveness’ mode of high-rate slickwater fracture designs, to a ‘fracture effectiveness’ mode provided by optimizing designs to achieve higher recoveries and better economics. This case study shows how advanced fracture fluid system designs have increased fracture effectiveness in an area of the Montney unconventional gas play.

The study focused on fifty multi-stage fractured horizontal wells in the dry gas area of the Heritage Montney Field in British Columbia, Canada. These wells were stimulated by different operators with a number of different fracturing techniques, fluid systems, etc. Wells were selected such that a sufficient variety of completion techniques were represented, and there was over 18 months of production history. A thorough review of the geology and petrophysical data within the area was undertaken in order to develop individual well descriptions for use in the production analysis (Rate Transient Analysis). Wells were history matched by varying reservoir permeability and fracture treatment properties. The results demonstrate that fracture effectiveness is a function of the fracture type and has a large effect on well productivity and economics.

This case study shows there is value in optimizing fracture designs through look-back studies, and that there is a need to focus on more effective fracture treatment designs in unconventional gas development. The results of the study show the importance of fracture fluid selection as well as both effective fracture half-length and fracture conductivity in maximizing the economic returns in this area of the Montney.
Comprehensive Fracture Calibration Test Design
Authors: Marongiu-Porcu Matteo , Retnanto Albertus , Economides Michael J. , Ehlig-Economides Christine
Published: June 2014

The formation permeability is an essential input for modem hydraulic fracture design. In tight formations estimation of formation permeability and pressure can be impractical or even impossible to determine by conventional pressure buildup transient tests because the formation virtually cannot flow without the fracture stimulation. Traditional fracture calibration tests including minifrac and data-frac provided estimates for the fracture minimum closure stress and the leakoff coefficient.

More recently, the continued acquisition of the injection falloff transient pressures after the fracture closure as in the Diagnostic Fracture Injection Test (DFIT) has provided estimates for formation permeability and pressure that could not have been determined from a conventional transient test. After-closure analysis can also yield permeability and pressure in conventional reservoirs and thereby eliminate the need for a pressure buildup test.

This paper provides a model for simulating the fracture calibration test to be used for test design and interpretation. The challenge for tight formations is to find an injection volume sufficient to create a suitable fracture while minimizing the closure time in the subsequent pressure falloff. This, in turn, reduces the time required to see after-closure transient features that are used for estimation of formation pressure and permeability. For higher permeability formations, the model enables estimation of the total test time including after-closure radial flow from which estimates of formation pressure and permeability are straightforwardly determined.

The design examples included in this paper are based on actual field data and demonstrate that fracture calibration tests provide an efficient and reliable means for determination of not only closure stress and the leakoff coefficient, but also the formation pressure and permeability, in the course of a realistic and viable amount of time.
Evolution of Frac-Pack Design and Completion Procedures for High Permeability Gas Wells in Subsea Service
Authors: Pandey Vibhas J. , Burton Robert C. , Nozaki Manabu
Published: June 2014

Frac-Pack techniques were used in a recent subsea well completion campaign. The sandstones layers targeted for completion are generally present in shallow gas reservoirs with depths ranging from 2,000 to 4,500ft [609.60 to 1,371.60m] TVDSS and exhibit a varying degree of consolidation. Core data shows that deeper pay intervals predominately comprise of fine grained, poorly consolidated sandstones with good porosity development and permeabilities in the 100 to 1000+mD range. These sand layers are often separated by shales and claystones. In contrast to this, the target sandstone layers in shallower intervals mostly consist of more consolidated rock with lower permeabilities in the 5 to 50mD range. Up to eight sand intervals are targeted in each well.

The subsea environment posed well completion design challenge because of the multi-layered completion strategy that was required to effectively drain several of the pay units in each well. Multi-zone, frac-pack completions consisting of isolation packers and sand control screens with separate pumping and production sleeves were used to provide sand control. An inner-string of additional isolation seals, gauges and intelligent control valves were run to provide zone specific monitoring and production control.

The initial well completion work resulted in high skin values during production. Review of post-stimulation data helped in identifying the shortcomings in designs and completion procedure. As a result of this, changes were made in the completion procedures, and frac-pack designs were tailored to suit the purposes. When these changes were implemented in subsequent wells, an improvement in well performance was seen, mostly in the form of reduced skin.

The paper details this evolution, including favorable modification of completion procedures, as well as, the changes in pump schedule, treatment planning, and delivery methods during the frac-pack campaign. The benefit of adopting such an approach, using the methods and techniques used in this campaign, can be applied to similar fields under development.
Multiple Fracture Initiation in Openhole Without Mechanical Isolation: First Step to Fulfill an Ambition
Authors: Chang Frank F. , Bartko Kirk , Dyer Steve , Aidagulov Gallyam , Suarez-Rivera Roberto , Lund Jeff
Published: June 2014

When a well is hydraulically fractured, the propagation of the fracture away from the wellbore is dictated by the far field stresses in the reservoir. However, the fracture initiation from the wellbore depends strongly on the near wellbore stress state created by drilling the well. Misaligned fracture initiation and propagation planes can reduce the wellbore-to-reservoir connectivity causing operation failure and high post fracturing skin.

Currently creating multiple fractures along a horizontal openhole requires mechanical isolation means such as openhole packers or sand plugs. They can be costly and time consuming. In addition, there is no control of fracture initiation within one isolated section. Undesirable competing fractures within the zone can occur to impact the fracture length. Significant improvement can be made if the factors controlling multiple fracture initiation without mechanical isolation can be understood.

Experimental work in multiple fracture initiation has been rare, controlled multiple fracture initiation is non-existent. Therefore a series of laboratory experiments was performed in a true tri-axial stress frame to investigate how multiple fractures can be initiated in a controllable fashion. In the tests, notches at specific locations along the openhole wellbore were created. The impact of the notch depth on the orientation of the hydraulically induced fractures was studied.

In addition to the experiments, continuum fracture mechanics modeling using finite element was also conducted to rationalize the experimental observations of fracturing initiation process in the rock.

The results of block tests provided new insight in multiple fracture initiation. By monitoring the real time acoustic emission events, the sequence of fracture creation as wellbore pressure increased was visualized. The finite element modeling gives simple criteria to explain the observed orientation of initiated fracture as a function of notch depth.
Measuring Field Supplied Proppant Conductivity – Issues Discovered in an Operator's Multi-Year Testing Program in the Bakken Shale
Authors: Pearson C. Mark , Griffin Larry , Chikaloff Julianna
Published: June 2014

The Bakken shale oil boom in North Dakota resulted in a two-year period of significant equipment, personnel and materials shortage in 2010 and 2011, following which a period of more rational supply and demand has been seen in the stimulation industry. Throughout the four year period Liberty Resources was designing and pumping multi-stage fracture treatments averaging ~4 Million pounds of ceramic proppant per well. A total of 88 wells were stimulated with 2565 separate fracture stages, placing over 283 Million pounds of proppant. At its height of activity the company managed two 24-hour frac fleets.

Key to the well design was the use of a high conductivity ceramic proppant in order to preserve longer term productivity from the wells which have closure stress approaching 10,000 psi. Ceramic proppants were initially categorized into one of three groups based on manufacturer supplied conductivity test data:

Highest performing proppants; these materials were given a preferred status for supply. Materials having conductivity that was close to Category A proppants; frac service companies were allowed to substitute these materials when no Category A proppant was available. Ceramic proppant that had test data significantly below Category A proppants; and were never to be utilized even if it meant postponing the fracture stimulation of the well.

Samples of each proppant type supplied to the field on each well site were sent for post-treatment testing at an independent testing laboratory to verify if the actual product delivered replicated the manufacturer supplied data that had been used in the design and the initial categorization of the proppant. Standard sieve, crush testing and a 50-hour long-term conductivity test were run on all samples.

This paper presents the results of these test data over the past four years. Significant results include:

As a standard across the industry it appears that while sieve data are in specification, manufacturer crush and conductivity technical data is only representative of the best materials being delivered to the well site. In a number of cases field proppant quality was significantly below that of the manufacturer's technical literature. After further investigation this resulted in some products being re-categorized lower than their initial Category A or B designations. Proppant pumped with severely reduced conductivity resulted in a measureable decrease in well productivity. As material supply options improved the company used the field testing data to select a preferred proppant with test data that consistently met the highest level of performance.
Analysis of US Hydraulic Fracturing Fluid System and Proppant Trends
Authors: Patel P. S. , Robart C. J. , Ruegamer M. , Yang A.
Published: June 2014

Building upon the analysis contained in a related paper (SPE-163875), "Analysis of U.S. Hydraulic Fracturing Design Trends," presented at the 2013 SPE Hydraulic Fracturing Technology Conference, this paper will provide a more comprehensive and robust analysis of hydraulic fracturing fluid systems and proppant trends across major shale plays in the United States between 2011 and the first half of 2013. This paper will present key insights gleaned from the categorization and analysis of over 55,000 hydraulic fracturing treatments, collected from FracFocus.org.

FracFocus.org is a website established in early 2011 with a centralized registry to provide hydraulic fracturing chemical disclosures across the United States. The website provides the data for the analysis presented in this paper, consisting of chemical disclosure records for nearly 55,000 hydraulically fractured wells. The data set includes information on all chemicals and proppants, fracture date, TVD, water volume, production type. We have collected all available data, identified key constituent materials, and classified each treatment according to a widely used set of frac type categories.

This paper investigates changes in key hydraulic fracturing technical parameters at the both the aggregate US level and regional level between 2011 and the first half of 2013. The analysis identifies changes over time in frac type, using the broad categories of conventional, water frac, hybrid, energized, etc. The paper also includes analysis on proppant trends, including usage rates for key proppant types (sand, resin-coated sand, and ceramics) and proppant loading trends.

To date, most knowledge of aggregate consumption trends on hydraulic fracturing chemicals and proppant is anecdotal and based on the direct experience of operators or service companies. This paper provides a more rigorous quantitative perspective on hydraulic fracturing fluid trends in the United States between 2011 and the first half of 2013.
Time Dependent B and D-Values, Scalar Hydraulic Diffusivity, and Seismic Energy from Microseismic Analysis in the Marcellus Shale: Connection to Pumping Behavior during Hydraulic Fracturing
Authors: Zorn Erich V. , Hammack Richard , Harbert William
Published: June 2014

The most accessible product of microseismic monitoring during hydraulic fracturing is the 3-dimensional seismic cloud around the wellbore. To realize the benefit of microseismic monitoring, we must quantify the data seismologically, spatially, and spatio-temporally, and compare this with pumping data and energy input/output to/from the system. Our goal is to quantify meaningful correlations between the fractal dimensions b (frequency-magnitude; <1 = compression, 1 = shear, >1 = tension) and D (spatial clustering; 0 = point, 1 = line, 2 = plane, 3 = cloud), calculated from microseismic data collected in the Marcellus Shale of Southwestern Pennsylvania. Limitations are related to the sensitivity and geometry of the acquisition system which affects microseism coordinates (and any calculated distances), magnitudes, signal/noise ratios, and energy arrivals.

We illustrate the evolution of b and D as a function of time through four stages, with between 328 and 1048 events per stage. In addition we compute the hydraulic diffusivity triggering front for each stage using time-distance plots and diffusivity contouring, the cumulative seismic energy and the s and p-wave energy components for each of the five stages. Plotting b, D, and diffusivity values as well as pumping pressure, slurry rate, proppant concentration, and seismic energy release against time will shed light on the complex down-hole interactions between fluid and rock that create and propagate fractures. In all stages, we see correlation between the b and D-values, but it is not consistently positive or negative throughout any stage. Changes in the correlation are accompanied by a change in pumping pressure, rate, and the frequency of microseismic events. An intriguing observation is a correlation between abrupt increases in total s-wave energy and decreasing b-value.

In addition, we introduce the concept of slow slip seismicity during hydraulic fracturing in the Marcellus Shale and its importance to the reservoir stimulation process. A preliminary analysis of data collected by a 2 Hz, three-component seismometer at the surface indicates the presence of this phenomenon and creates an opportunity to extend this research into the Appalachian Basin.
Harmonization of Quantitative Risk Assessment (QRA) Studies in One Company’s Affiliates
Authors: Fardeau Benoit , Augustin Antoine , Ait Malek Amal , Rualt David
Published: June 2014

GDF SUEZ Exploration & Production INTERNATIONAL (EPI) is committed to grant the same level of safety in all its facilities worldwide.

Over the years, Quantitative Risk Assessment (QRA) has established itself as a standard component of the risk management program for offshore and onshore facilities.

The QRA studies in the different affiliates of GDF SUEZ EPI vary depending on country regulations, experience and complexity of the facilities. The affiliates refer to internal methodology when conducting these studies. Risk Acceptance Criteria used during these QRA studies are affiliate dependant.

GDF SUEZ EPI believes there is a benefit in developing a consistent approach in the review of risks associated with operations. This approach is contributing to improve the relevance of the QRA studies,share feedback of QRA between affiliates,compare results of the QRA studies in different regulatory regimes,bring the assurance to corporate management of the quality of risk assessments.

The central component of this harmonized approach is to promote common practices regarding Quantitative Risk Assessment and related Risk Acceptance Criteria. This study covers the following points: Comparing existing practices and QRA methodology in the different affiliates,Integrating the Regulatory guidance in making the required demonstrations in QRA studies,Reviewing recommendations by OGP, standards and regulations (HSE-UK, NORSOK, NL, etc.) to determine best practices.Harmonizing QRA studies (Common methodology, Level of detail of these studies, ALARP demonstration, QRA for major changes, etc.)

This analysis investigates the QRA process, the selection and use of databases and analytical techniques, the effect modeling, and the risk acceptance criteria.

The study will improve practices for operations performed under the control of GDF SUEZ EPI by enhancing the safety of its installations and grant that affiliates use "all measures necessary" to avoid major risks.
Successfully Drilling Sidetrack # 7 with MPD/UBD Combination after Six Failed Conventional Drilling Attempts
Authors: Medley George H. , Elmore Robert J. , Goodwin Robert C. , Nauduri Sagar
Published: June 2014

Conventional drilling methods initially utilized to drill an east Texas HPHT well, presented in this case history, ultimately failed after six attempts were made by an independent operator to drill a "straightforward" horizontal wellbore. The subject HPHT well proved extremely challenging with reservoir BHT of 334°F and approximate 13,900 – 14,500 psi reservoir pressure. The well was plagued by several drilling problems including multiple well-control incidents, a casing failure, surge-swab issues, stuck pipe incidents, trip problems, directional control issues, and finally a blowout.

Utilizing a combination of MPD and UBO techniques, Sidetrack Number 7 successfully met all project and geologic objectives. A Wide variation of pore pressure and fracture pressure equivalent mud densities made accomplishing a primary goal of MPD, ("to precisely control the annular pressure profile throughout the wellbore") difficult but possible, requiring the combination of methods. Neither MPD nor UBO could be consistently utilized while drilling. When precise wellbore pressure management proved difficult due to the pressure regime variations, modification of the MPD technique and application of UBO accompanied by reconfiguration of the BOPE ultimately facilitated optimum control during several subsequent incidents.

Key elements to success were: a) proper understanding of the physics supporting each variation of MPD and UBO used, b) thorough engineering of all problems and preparation of multiple contingency procedures, c) extensive training of all personnel related to drilling and completing the well, including rig crews, engineers, managers, vendors and support crews, and d) involvement of a highly experienced MPD/UBO team.
Overcoming a 0.35 ppg Mud Weight Window - A Case History of Successful Automated Managed Pressure Drilling and Managed Pressure Cementing Offshore Malaysia
Authors: Ming Lee Jin , Mousa Mohammed , Setiawan Trigunadi B. , Saikam Warjanto , Raju Sagi V. , Zahir Ahmad , Afiqah W. Nor , Noor M. Abshar , Omar M. Mizuar , Rodriguez Freddy Rojas , Prasetia Andi Eka , Richards Dylan , Gallo Fernando
Published: June 2014

TA is an over-pressurized well in the field development project located Offshore Peninsular Malaysia. Although the well was drilled as a development well, it also had an exploration objective as it was the first to penetrate the over pressured zones across a fault in the TA field.

An initial attempt to drill conventionally resulted in severe gain and loss scenarios across the first of three sands 80 m below the 7" casing shoe, primarily due to weak coal formations. After many attempts to control losses, it was decided to plug-abandon the 6" open hole and to temporarily suspend the well due to insufficient operating window to drill ahead. After a year of suspension, a new drilling approach using a statically underbalanced mud weight (MW) in combination with an Automated Managed Pressure Drilling (MPD) system was introduced as the best solution for drilling into the well objectives. During the planning stage, different scenarios were analyzed based on the formation fracture gradient (FG) and pore pressure (PP) estimations. MPD plans were designed based on statically underbalanced mud while drilling, running the liner, and during the cementing job.

During drilling, Dynamic Flow Checks (DFC) and Dynamic Formation Integrity Tests (DFIT) were performed using the MPD system to identify and confirm operating window. The target total depth was successfully reached with mud weighted within the narrow 0.35 ppg drilling window (17.8–18.1 ppg). Decision was then made to top kill the well at 1200 m-MDDF with 18.30 ppg mud, providing an overbalanced condition of 85 psi. Open hole logging operations were then successfully executed. The well was then displaced to a 16.30 ppg mud prior to performing Managed Pressure Cementing (MPC). This technical paper aims to discuss all of the MPD - MPC challenges faced and best practices developed during both the planning and execution stages of the program.
A Case Study: First Field Application of Fully Automated Kick Detection and Control by MPD System in Western Canada
Authors: Kinik K. , Gumus F. , Osayande N.
Published: June 2014

Detection and control of gas kicks in OBM/SBM while drilling through narrow pore - fracture windows has always been a challenge due to gas solubility and mud compressibility. Continuous closed loop monitoring of the well and automated early kick detection and control helps to keep the influx volume at a minimum before it reaches the "well control" threshold margin in the kick tolerance matrix.

This paper presents a case study and detailed analysis of the event through advanced simulations to examine the benefits of automated influx detection and control using MPD system in comparison to conventional well control method. In the case study, an automated MPD system successfully detected and controlled a gas influx in OBM while drilling onshore Western Canada. The analysis employed dynamic well control simulations to regenerate the event and a close match with the field data was achieved. A sensitivity analysis was then conducted to study the effect of total response time on pressures at the surface and at the casing shoe during the application of conventional Driller’s method of well control.

The findings from the study demonstrate how automated early kick detection and control minimizes influx volume and increases operational safety. The implementation of MPD system with such capabilities significantly reduces NPT by enabling influx circulation at full rate and eliminating the need for flow-check, BOP closure and operational delays inherent in conventional well control.
Dual Gradient Screening Tool: Depth Ratio (DRx) and pDRx Matrix Method
Authors: Nauduri Sagar , Medley George , Tian Shifeng
Published: June 2014

After evaluating multiple well profiles to determine feasibility of performing Dual Gradient Drilling (DGD), a need became apparent for a simpler screening tool that can quickly demonstrate the utility of a given DGD variation compared to other drilling methods. Subsequently, the ‘Depth Ratio method’, or ‘DRx Method’ and ‘Density Depth Ratio Matrix Method’ or ‘ρDRx Matrix Method’ have been developed. These methods utilize basic physics to evaluate DGD’s utility, and are independent of factors such as geographic location and DGD method.

DGD helps in adjusting the pressure exerted by the drilling fluids on the open wellbore and formation by conveniently splitting the annular pressure profile into two separate and manageable gradients at the ‘point of dual gradient (DGp)’. At DGp, there can be modifications to systems’ a) net energy content, b) overall mass, or c) both.

Using the ‘DRx method’ and computing a ‘ρDRx matrix’, the utility of a given DGD system performing under its minimum and maximum densities (where mass and energy changes are expressed in equivalent densities), can be evaluated. This gives a range of feasible operation for the DGD system. This information can then be compared to actual pressure profiles that are being tested for DGD, and a very quick screening for possible application of DGD can be performed.

DRx and ρDRx matrices can be applied for both ‘Normal Gradient Drilling’ (regular/abnormal pressure profiles) and pressure regression profiles (i.e., "Reverse Gradient Drilling").
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

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

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.