bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comprehensive Fracture Calibration Test Design
Authors: Marongiu-Porcu Matteo , Retnanto Albertus , Economides Michael J. , Ehlig-Economides Christine 
Published: June 2014

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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; &lt;1 = compression, 1 = shear, &gt;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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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").