bluuebunny/crossref_metadata_2025 huggingface dataset:
Sand, Resin-Coated Sand or Ceramic Proppant? The Effect of Different Proppants on the Long-Term Production of Bakken Shale Wells
Authors: Hu Kyle , Schmidt Andrew , Barhaug Jessica , Wong Joe , Tian Jiaher , Hall Bobby E.
Published: September 2015

Proppants and their effect on the production of wells are not thoroughly understood. When selecting a proppant, operators deliberate: “Do I purchase a low-cost proppant to reduce completion costs or do I spend more for higher conductivity to increase long-term production and greater return on my investment?” Good well data can be difficult to obtain and completion designs can vary. Hence, only a few existing case histories provide apples-to-apples comparisons of long-term production performance based on the use of different proppant types.

Continuing our prior research (SPE Paper 169544), we present data that will help operators make informed decisions when selecting proppants for optimizing Bakken wells. To investigate effectiveness of different proppants, researchers tracked long-term production rates of several comparable well sets. For example, in the first study, three wells on the same pad in the Haystack Butte Field in McKenzie County, North Dakota were completed by one operator. A second study included 11 Bakken wells fractured by another operator in the Grail Field in McKenzie County.

All three wells in Haystack Butte Field were hydraulically fractured with similar completion methods. The only significant difference was the proppant type. One well used 100% uncoated sand, another well combined 45% uncoated sand with 55% resin-coated sand, and the third well used 45% uncoated sand and 55% ceramic proppant. The well completed with sand and ceramic proppant did not have the highest initial production rate (IPR), but had, on average, 20% higher production over a 365 day period. The well where sand was combined with resin-coated sand produced a higher IPR. However, over 365 days, that well's production was outpaced by the other two wells with the sand/ceramic well delivering the best long-term production of all three. Similar findings were confirmed among the wells in the Grail Field. This study focused on 11 Bakken wells that used sand with a tail in of 30% to 40% ceramic proppant, sand with a tail in of 30% resin-coated sand, and sand with 50% higher volume. It also indicated that using a high percentage and high volume of ceramic proppant delivers superior long-term economic benefits in Bakken wells.

These findings, in addition to others outlined in the paper, challenge the preconception that wells completed using ceramic proppant should deliver higher initial production rates. Time and again, the findings demonstrated that the long-term production of Bakken wells completed with ceramic proppant significantly outperforms wells completed exclusively with other proppant types. Moreover, data demonstrates that compared to sand-only completions, resin-coated sand helped improve initial production but did nothing to improve long-term production, especially in deeper wells.
Study on Inhibition of High-Molecular-Weight Paraffins for South Eagle Ford Condensate
Authors: Gawas Kiran , Krishnamurthy Pushkala , Wei Fang , Acosta Erick , Jiang Ying
Published: September 2015

The deposition of high-molecular-weight paraffins in crude oil and condensates, especially with an average carbon number greater than 40, is difficult to treat using chemical methods. Expensive physical remediation methods, such as hot oil treatments and pigging, must be used in such cases. This paper describes the development of paraffin inhibitors for the targeted inhibition of waxes having an average carbon number greater than 40. The study was conducted for condensates from the South Eagle Ford shale formation.

The effect of inhibitors on deposition was studied using a cold finger testing method. A testing protocol was developed to target the deposition of high-molecular-weight waxes having an average carbon number greater than 40. The effect of paraffin inhibitors on the deposits was characterized using high-temperature gas chromatography (HTGC) and differential scanning calorimetry (DSC) techniques. The paraffin inhibitors commonly used tend to inhibit smaller chain paraffins and thus increase the relative amount of longer chain paraffins. This tends to form harder deposits, which are difficult to treat. The new class of inhibitors developed in this study showed improved performance with regard to preventing the deposition of waxes containing high-molecular-weight paraffins. HTGC analysis of the cold finger deposits showed more than a 50% reduction in the deposition of paraffins having a carbon number greater than 40 for the inhibitors tested. In addition, the use of inhibitors resulted in softer deposits. Thus, using inhibitors targeted at the heavier paraffins that soften the deposit could reduce the frequency of hot oiling and pigging operations required in field applications.
Using Radial Bond Segmented Waveforms to Evaluate Cement Sheath at Varying Depths of Investigation
Authors: Frisch Gary , Fox Phillip , Hospedales Dexter , Lutchman Krishna
Published: September 2015

The radial bond tool consists of multiple receivers normally 2 to 3 ft from the source in addition to the standard 3 to 5 ft of receiver spacing. The standard interpretation from these tools consists of 6 to 8 amplitude measurements presented as either curves or as an image, indicating circumferential cement to casing bond. Evaluating bond quality of the annular space between casing and formation has been extremely difficult using existing logging tools and interpretation techniques. The discussed technique processes segmented waveforms in an innovative way, providing additional circumferential cement bond information at varying depths of investigation in annular space.

A new method of interpretation has been applied to the cement bond log (CBL) waveform that examines the peaks and troughs of the waveform to help determine the cement bond between the casing and formation. The interpretation provides up to four different amplitude curves at different depths of investigation in the annular space. Applying the same methodology to the segmented waveforms, but with additional steps, allows the circumferential bond to be determined between the casing and formation. Depending on the length of the segmented waveforms, these annular shells can extend from the casing to the formation, and can be corrected for the relative bearing of the tool.

The example is a standard cement evaluation immediately above and below the surface casing shoe, with a washout immediately below the casing shoe. Both the raw and advanced cement evaluation revealed poor bond in the washout region. With the new processing of the radial waveforms, a channel in the annular space was shown to extend almost all the way to the surface, which is not visible using standard interpretation techniques. Using older standard evaluation techniques, the channel would have been missed or incorrectly evaluated. The use of the radial shell technique provided accurate interpretation of the annular space between the casing and formation.

Standard interpretation of radial bond data does not include use of segmented waveforms. With this new processing technique, not only are the segmented waveforms used, but the annular space is broken into regions or circumferential shells, which can be further evaluated. These shells allow evaluation between the casing and formation, and allow a more accurate and complete evaluation of the cement sheath. This can help provide a more precise assessment of wellbore integrity and help prevent loss of the wellbore attributed to cement and or casing failure.
The Effects of Fracture Orientation and Elastic Property Anisotropy on Hydraulic Fracture Conductivity in the Marcellus Shale
Authors: McGinley Mark , Zhu Ding , Hill A. Daniel
Published: September 2015

Production of hydrocarbons from low-permeability shale reservoirs has become economically feasible thanks to advances in horizontal drilling and hydraulic fracturing. Together, these two techniques help to create a fracture network, which act as fluid conduits from the reservoir to the wellbore. The efficacy of a fracturing treatment can be determined through fracture conductivity analysis. Fracture conductivity is defined as the product of fracture permeability and fracture width, and describes both how much and how easily fluid can flow through fractures. It is therefore directly related to well performance.

The goal of this work is to explore fracture conductivity of Marcellus shale samples fractured in both horizontal and vertical orientations. The Marcellus shale, located primarily in Pennsylvania, Ohio, West Virginia, New York, and Maryland, is the largest gas-bearing shale formation in North America, and its development has significant implications on regional economies, the energy infrastructure of northeast United States, and the availability of petrochemical plant feedstock.

In this work, a series of experiments was conducted to determine the propped fracture conductivity of 23 different outcropsamples from Elimsport and Allenwood, Pennyslvania. Before conductivity measurements were taken, the pedigree of samples was verified through XRD analysis, elastic rock properties were measured and compared against literature values, and fracture surface contours were mapped and measured. Fracture conductivity of both horizontally and vertically-fracture samples was determined by measuring the pressure drop of nitrogen gas through a modified API conductivity cell.

Results show that fracture conductivity varies as a function of fracture orientation only when anisotropy of the rock's mechanical properties is pronounced. It is hypothesized that the anisotropy of Young's Modulus and Poisson's Ratio play a significant role in fracture mechanics, and therefore in the width of hydraulically-induced fractures. Ultimately, the experiments conducted as part of this work show that fracture conductivity trends are strongly tied to both proppant concentration and the rock mechanical properties.
Blowout Prevention and Relief Well Planning for the Wheatstone Big-Bore Gas Well Project
Authors: Upchurch Eric R. , Falkner Sam , House Andrew
Published: September 2015

The offshore Wheatstone LNG Project in Western Australia utilizes subsea big-bore gas wells as the preferred method of producing the field. Wheatstone wells use a 9–5/8” production conduit from the top of the gas pay zone to the ocean floor. Well bores of this size are necessary to match the large productive capacity of the gas reservoirs they penetrate. This producing scenario provides the obvious benefit of yielding large volumes of gas through the use of relatively few wells. Each of those highly productive wells, however, also represents a source of gas that, if accidently allowed to flow unhindered, could present an uncommonly difficult well control challenge. It is for this reason that the Wheatstone Drilling and Completions Team evaluated a wide range of possible reservoir and well architecture scenarios to fully understand the possible scale of relief well responses that might be necessary in the event of a blowout. The conclusions from this evaluation were surprising. Our originally-planned well design concept called for penetrating the Wheatstone gas reservoirs with a casing shoe set 950m vertically above. Our analysis indicated that 3–4 relief wells would be simultaneously required to bring a blowout under control. Based on these results, both the well and the drilling execution plan were redesigned to minimize the number of required relief wells. In summary, the redesign amounted to setting casing immediately (i.e., ≤ 3m) above the gas reservoir before actually penetrating it, with the resulting benefit of reducing the required number of relief wells to 2. Although this reduction is beneficial, it should be noted that there is only one documented subsea case where 2 or more relief wells have been drilled with the intent of simultaneously pumping into both to effect a dynamic kill. Given this fact, our well control-related preparations for executing this project were more extensive than that of preceding projects.

This paper chronicles the full extent of the engineering and operational planning performed to ensure that no uncontrolled hydrocarbon releases occurred during the execution of the Wheatstone Project's subsea big-bore gas wells and, if a blowout were to occur, that the response to such an unprecedented event would be sufficient and robust. Covered in the paper are (1) reservoir deliverability modeling, (2) dynamic kill modeling, (3) gas plume modeling, (4) relief well trajectory and mooring planning, (5) pilot hole execution planning, (6) a newly applied LWD technology for sensing resistivity vertically below the drill bit and (7) a discussion of future research that has been identified as necessary to better define the fluid injectivity capabilities of subsea relief wells.
Packing The Unpackable: How The Use Of Best Sand Control Technologies Reversed The Marginal Project Of Atlanta In A Promising Development
Authors: Pedroso Carlos A. , Liborio Fernando , Rausis Mauro , Moreira Marivaldo , Salies Jacques B.
Published: September 2015

“To produce the most viscous oil from completely unconsolidated sandstone in ultra deep waters”. This summarizes the challenges to construct the wells to exploit the Atlanta field, Santos Basin, Brazil. The ultra deep water of 1550m, the use of a powerful subsea ESP with 1,600 HP, the need of long (850 m) open hole horizontal gravel pack (OHHGP), the low burial depth (800 m) resulting in low reservoir temperatures (100 F) and extremely low fracture gradient (0.50 psi/ft), the highest acidity of a crude (TAN=9.8) are some of the difficulties that had been overcome to drill, complete and test the first 2 production wells of the Atlanta Field.

Atlanta is a post-salt oil field located 185 km off the coast of Rio de Janeiro. The field was discovered in 2001 and during the same year a deviated well was drilled to test the eocenic sandstones. A cased hole gravel pack was installed in 90m of perforated interval. The completely unconsolidated sandstone showed high porosity (36%) and high permeability (5D). While the rock properties are excellent, the oil is heavy and viscous (14° API and 228 cP in reservoir conditions), with the highest acidity registered (TAN=9.8).

In 2006, a horizontal well was drilled to test the full potential of this kind of construction, which included and OHHGP, and to validate the field development concept. However, crucial problems were faced during the drilling and completion phase. Directional control problems led to two sidetracks. The horizontal section experienced massive fluid loss. Only part of the screens was run in the open hole. The attempt to pack the screens, with alpha-beta waves, resulted in a premature screen out leaving a SAS completion. Even after these problems, the well was tested, with solid production causing the ESP failure. The partially conclusive DST showed a severe damaged well, with high skin of 40.

The bad experience in constructing a horizontal well in these challenging conditions compromised the reliability of the project. But in 2012, a new operator decided to revisit this project. After considering technology improvements, an extensive preparation and a complete assessment of past operations were performed. Finally, in 2013 and 2014, 2 wells were drilled and, using the best technologies, 100% packed in the full horizontal length (800m) drilled. Both wells were tested showing zero skin.

This paper presents the main challenges and how they were overcome by using the best sand control techniques, resulting the successful construction, gravel packing and testing the first two production wells, recovering the reliability of the project and encouraging to move on to the next phase.
How Big is Too Big? Assessing Seismic Hazard and Hydraulic Fracture-Induced Seismicity
Authors: Bowman-Young Sheri , Urbancic Ted , Viegas Gisela , Meighan Lindsey , VonLunen Eric , Hendrick Jason
Published: September 2015

A vast number of the reported cases of increased seismicity of moderate magnitude (Mw > 0) earthquakes seem to be tied to some form of fluid injection activitiy, being it wastewater disposal by injection into deep wells or high pressure fluid injection into oil and gas reservoirs to hydraulically fracture the rock and improve hydrocarbon recovery. Regulations have been proposed to implement traffic light systems to dictate the responses that the industry needs to take based on either the magnitudes or observed particle velocities or accelerations on the surface. In order to relate the seismic hazard potential in seismically active areas, empirical ground motion prediction equations (EGMPE) are used to relate event parameters like magnitude and location to site characteristics such as peak ground acceleration (PGA) or peak ground velocity (PGV) which tend to be how building codes are parametrized. Therefore, local hazard assessment near hydraulic fractures that generate relatively large magnitude events need to be estimated more precisely by developing and using local EGMPEs.

Hybrid deployments combining 15Hz downhole and low frequency near-surface geophones can be used to accurately capture both the localized microseismic events and any large magnitude events associated with hydraulic fracture monitoring across North American basins – Horn River, Eagle Ford, Barnett, and Montney for example. In our studies events with M>0 are observed for completions in these formations. While in many cases the magnitude of these events is too small to be felt on the surface, there are reports of higher magnitude events which have been sensed by workers on site and the local population.

The exact relationships between magnitudes and shaking are not necessarily one-to-one. Shaking also varies based on the stress release of the events. As summarized recently by Hough (2014) for other fluid-induced seismicity, the lower stress releases typical for these sequences results in on-average less shaking than is observed for equivalent magnitude tectonic events. In order to quantify shaking over a seismogenic volume, we show how to develop EGMPEs based on the North-American examples. The EGMPE methodology developed in this study can be extrapolated for similar earthquakes of larger magnitude and included into future probabilistic hazard and risk analysis for induced seismicity as related to hydraulic fracture stimulations.
Advanced Modeling of Interwell Fracturing Interference: an Eagle Ford Shale Oil Study
Authors: Marongiu-Porcu Matteo , Lee Donald , Shan Dan , Morales Adrian
Published: September 2015

To investigate interwell interference in shale plays, a state-of-the-art modeling workflow was applied to a synthetic case based on known Eagle Ford shale geophysics and completion/development practices. A multidisciplinary approach was successfully rationalized and implemented to capture 3D formation properties, hydraulic fracture propagation and interaction with a discrete fracture network (DFN), reservoir production/depletion, and evolution of magnitude and azimuth of in-situ stresses using a 3D finite-element model.

The integrated workflow begins with a geocellular model constructed using 3D seismic data, publicly available stratigraphic correlations from offset vertical pilot wells, and openhole well log data. The 3D seismic data were also used to characterize the spatial variability of natural fracture intensity and orientation to build the DFN model. A recently developed complex fracture model was used to simulate the hydraulic fracture network created with typical Eagle Ford pumping schedules. The initial production/depletion of the primary well was simulated using a state-of-the-art unstructured-grid reservoir simulator and known Eagle Ford shale pressure/volume/temperature (PVT) data, relative permeability curves, and pressure-dependent fracture conductivity. The simulated 3D reservoir pressure field was then imported into a geomechanical finite-element model to determine the spatial/temporal evolution of magnitude and azimuth of the in-situ stresses.

Importing the simulated pressure field into the geomechanical model proved to be a critical step that revealed a significant coupling between the simulated depletion caused by the primary well and the morphology of the simulated fractures within the adjacent infill well. The modeling workflow can be used to assess the effect of interwell interferences that may occur in a shale field development, such as fracture hits on adjacent wells, sudden productivity losses, and drastic pressure/rate declines. The workflow addresses the complex challenges in field-scale development of shale prospects, including infilling and refracturing programs.

The fundamental importance of this work is the ability to model pressure depletion and associated stress properties with respect to time (time between production of the primary well and fracturing of the infill well). The complex interaction between stress reduction, stress anisotropy, and stress reorientation with the DFN will determine if newly created fractures propagate toward the parent well or deflect away. The technique should be implemented in general development strategies, including the optimization of infilling and refracturing programs, child well lateral spacing, and control of fracture propagation to minimize undesired fracture hits or other interferences.
Analysis of the Effect of Eccentricity on Displacement of Non-Newtonian Fluids with a Hybrid Method
Authors: Xie Liangjun , Chaudhary Saleem , Chen Zhongming
Published: September 2015

The effect of eccentricity on pressure drop and mud displacement in annular flow is an important topic in drilling and cementing. Most researchers have focused on the effect of pressure drop with eccentricity and pipe rotation in drilling. In cementing, determining the fluid rheology and flow profile is important to the success of mud displacement and cement placement. Most recent researchers have adopted computational fluid dynamics (CFD) models to obtain results with Newtonian, or Power Law, or Bingham Plastic models. However, they are slow in computation and need special software to run, and thus are not readily applicable to the field. Furthermore, there are few results with the Herschel-Bulkley model, which is widely used in the industry. It is necessary to design an algorithm that can predict eccentric pressure drop, fluid rheology and flow profile in the annular cross-section accurately and efficiently.

In this paper, we introduce a novel hybrid algorithm to predict the effect of eccentricity on pressure drop and fluid velocity profile in the annular cross-section. First the pressure drop with concentric wellbore geometry is calculated as an initial guess. Second, similar to CFD and finite element method (FEM), the annular cross-section is divided into small mesh elements. Equations governing the condition must be adapted to the geometry of each mesh element. Third, iterations are executed over pressure drop, fluid velocity, and flow rate in each mesh element until the total flow rate converges. Breaking the gel and critical velocity are important to determine the flow status in the mesh element.

The proposed hybrid algorithm includes the Newtonian, Power Law, Bingham Plastic, and Herschel-Bulkley rheology models. Simulation and job history data are used to investigate the effect of eccentricity on the pressure drop, fluid rheology, and flow status in the annulus. Observations indicate that increasing eccentricity decreases the frictional pressure drop. This matches the results in the literature. We also observed that the fluid tends to remain stationary in regions with a narrow gap, while the wide side may maintain turbulent flow. Normally, laminar and static areas are predominant for typical fluids. In addition to predicting reasonable trends, the hybrid algorithm is efficient and accurate.

A hybrid algorithm has been proposed to investigate the effect of eccentricity on frictional pressure drop and mud displacement in the annular cross-section. It is applicable to the main rheology models, and it works accurately and efficiently. The hybrid algorithm is described along with discussion of results over the typical range of geometries encountered.
Design, Construction and Operation of an Automated Drilling Rig for the DSATS University Competition
Authors: Bavadiya V. A. , Aljubran M. J. , Kibe J. M. , Christy S. M. , Le H. N. , Ahmed R. , Florence F.
Published: September 2015

The Drilling Systems Automation Technical Section (DSATS) is a group of SPE volunteers from many nations, connected by their belief that drilling automation will have a long-term, positive influence on the drilling industry. DSATS implemented a student competition to encourage new entrants into the drilling industry who might consider creating and using automation tools and techniques in future drilling programs. The competition brings a hands on approach to the complex, multifaceted problem of drilling systems, expanding the breadth of knowledge and creative thought processes of the individuals who participate. This project challenges students who plan to become petroleum engineers and other students in related disciplines who may not currently think of the upstream drilling industry as a career opportunity. The competition requires university teams to design and build laboratory-scale drilling rigs to automatically drill through a sample of material unknown to the students. This paper presents the winning students' summary of the rig design, construction and operation of their test results and how it relates to their new understanding of the drilling process.

In the fall of 2014, student teams from different petroleum engineering schools designed a rig that can drill through a concrete block filled with unknown formations while dealing with a drill bit and drillpipe chosen to ensure some common drilling dysfunctions. Based on the rig design, finalists from four universities were selected to move to the second phase of the competition (i.e. construction and testing phase). In the early-spring of 2015, the teams built their rigs. In May and June, they demonstrated the performance of their rig design and control algorithms by drilling the samples while witnessed by DSATS members.. The winning team received a travel grant to attend the ATCE to present this paper that addresses:

Drilling limitations and critical parameters Construction issues and initial operations that required a re-design Final design criteria, constraints, tradeoffs How key decisions were determined Summary of recorded data and key events Drilling parameters and how they impacted the test Economic considerations Significant new team learnings Other items of interest Conclusions and recommendations

We believe this to be the first competition of this kind that requires multi-disciplinary teams to work jointly within a university setting, which prepares them for the integrated team approach currently in use throughout our industry. Their designs are practical, but are not limited by the historical features that are commonly included in today’s commercial rig designs.
Strategic Insights From Faltering Exploration Results
Authors: Wilson J. P. , Highton D. G. , Wilson A. , Latham A. , Miles S. , Utz A. , Toulmin S.
Published: September 2015

The health of conventional exploration had been suffering before the oil price crash in 2H 2014; commerciality and value creation both declined dramatically over the past five years. Overall discovered conventional volumes reached exceptional peaks of between 30 and 50 billion boe per year in the years 2009-2012, dominated by two mega-plays: the pre-salt in Brazil and East African gas. The next two years were disappointing in comparison, although average discovery sizes, volumes added per well and success rates held up well. Returns from conventional exploration have been on a downward trend for a decade. The proportion of gas grew, as did the share of volumes found in deepwater. Cost escalation was exacerbated by increasing complexity of both exploration and development. A growing emphasis on frontier deepwater plays resulted in several country-opening oil discoveries. However, these finds fell short of the giant size required to anchor a deepwater development in countries like Sierra Leone, Cote d'Ivoire and French Guiana. In the first half of the past decade, 70-80% of oil volumes are deemed commercial, but the proportion drops to 30-60% in the second half. A shift back towards mature offshore basins is underway and will accelerate in the near term. As the top explorers struggled to replace resources and create value from conventional exploration, many turned to exploration of unconventional resources. Volume additions were undoubtedly strong for most companies, but to outperform by value creation from exploration in resource plays in North America, companies must be first, fast and focused. These trends may hold lessons for those wishing to avoid the short-termism of the current environment. Companies with an appetite for counter-cyclical moves could capture long-term, low-cost resource opportunities, establishing a strong prospect pipeline and building a flexible portfolio that plays to their strengths.
Experimental Investigation of Three-Phase Low Liquid Loading Flow
Authors: Karami Hamidreza , Torres Carlos F. , Pereyra Eduardo , Sarica Cem
Published: September 2015

An experimental study is conducted using a 6-in ID facility to investigate characteristics of three-phase stratified wavy flow in horizontal pipelines. The experiments are conducted under low liquid loading condition, which is very commonly observed in wet gas pipelines. The analyzed flow characteristics include wave pattern, liquid holdup, water holdup, pressure gradient, and wetted wall fraction.

The experimental range covers superficial gas velocity, νSg, values of 8-23 m/s, superficial liquid velocity, νSL, values of 1-2 cm/s, and inlet liquid stream water cut values of 0-100%. Differential pressure transmitters, a quick closing valve and pigging system, and a high speed camera are used to acquire the data. The trends of the data with respect to input parameters are investigated. The performances of commonly used models are compared to liquid holdup, pressure gradient and water holdup experimental results.

The observed wave patterns include stratified smooth and stratified wavy with 2-D waves, 3-D waves, roll waves, and atomization flow. The transitions between the flow patterns vary as a function of water cut. The trends of pressure gradient, liquid holdup, and water holdup with respect to vSg, vSL, and water cut are observed and interpretations based on physics are provided. The predictions of a transient multiphase simulation software, TUFFP Unified Model v. 2012, Beggs and Brill (1973), Taitel and Dukler (1976), and Xiao et al. (1990) are compared to the acquired experimental data. The results from transient multiphase simulation software, Taitel and Dukler (1976) and Xiao et al. (1990) are in good agreement with experimental liquid holdup and pressure gradient data. But the three-phase water holdup trends are not predicted well. The complicated nature of liquid-liquid interactions in three-phase low liquid loading flow causes higher uncertainties in predictions.

The number of experimental three-phase data, especially with larger pipe diameters, is very limited. This paper provides with comprehensive data for three-phase stratified flow for a 6-in ID pipe. In addition, the prediction performance of the commonly used predictive tools in the industry is provided.
The Use of a pH-Triggered Polymer Gelant to Seal Cement Fractures in Wells
Authors: Ho Jostine Fei , Patterson James W. , Tavassoli Shayan , Shafiei Mohammadreza , Balhoff Matthew T. , Huh Chun , Bommer Paul M. , Bryant Steven L.
Published: September 2015

The potential leakage of hydrocarbon fluids or CO2 out of subsurface formations through wells with fractured cement or debonded microannuli is a primary concern in oil and gas production and CO2 storage. The presence of fractures in a cement annulus with apertures on the order of 10–300 microns can pose a significant leakage danger with effective permeability in the range of 0.1–1 mD. Leakage pathways with small apertures are often difficult for conventional oilfield cement to repair, thus a low-viscosity sealant that can be placed into these fractures easily while providing a long-term robust seal is desired. The development of a novel application using pH-triggered polymeric sealants could potentially be the solution to plugging these fractures.

The application is based on the transport and reaction of a low-pH poly(acrylic acid) polymer through fractures in strongly alkaline cement. pH-sensitive microgels viscosify upon neutralization with cement to become highly swollen gels with substantial yield stress that can block fluid flow. Experiments in a cement fracture determined the effects of the viscosification and gel deposition via real-time visual observation and measurements of pressure gradient and effluent pH. While the pH-triggered gelling mechanism and rheology measurements of the polymer gel show promising results, the polymer solution undergoes a reaction caused by the release of calcium cation from cement that collapses the polymer network (syneresis). It produces an undesirable calcium-precipitation byproduct that is detrimental to the strength and stability of the gel in place. As a result, gel-sealed leakage pathways that subjected to various degrees of syneresis often failed to hold back pressures.

Multiple chemicals were tested for pre-treatment of cement cores to remove calcium from the cement surface zone to inhibit syneresis during polymer placement. A chelating agent, sodium triphosphate (Na5P3O10), was found to successfully eliminate syneresis without compromising the injectivity of polymer solution during placement. Polymer gel strength is determined by recording the maximum holdback pressure gradients during liquid breakthrough tests after various periods of pre-treatment and polymer shut-in time. Cores pre-treated with Na5P3O10 successfully held up to an average of 80 psi/ft, which is significantly greater than the range of pressure gradients expected in CO2 storage applications. The use of such inexpensive, pH-triggered poly-acrylic acid polymer allows to seal leakage pathways effectively under high pH conditions.
The Role of Induced Un-propped (IU) Fractures in Unconventional Oil and Gas Wells
Authors: Sharma M. M. , Manchanda R.
Published: September 2015

The term induced un-propped (IU) fractures refers to fractures created around the main propped fracture which are too small to accommodate any proppant. These could include natural fractures, and micro-fractures induced along bedding planes or along other planes of weakness. Based on production data, diagnostic methods and field observations it is becoming increasingly clear that induced un-propped fractures created during the hydraulic operation play a critical role in determining the success of fracture treatments.

In this paper five independent pieces of evidence are presented to prove the existence of induced un-propped fractures in most wells under downhole conditions and to demonstrate their importance in production. These include: micro-seismic data, production history matching, tracer data, pressure communication between wells and finally calculations on the fate of the injected fracturing fluids. Examples are provided to clearly demonstrate how this information indicates the presence of IU fractures.

Once the existence of these fractures has been demonstrated simulations are conducted to show what role these induced un-propped fractures play during fracturing and during short-term and long-term production. It is shown that shale properties and the rheology and rate of injection of fracturing fluids plays an important role in the spatial extent and width of IU fractures. In some shales these fractures play a dominant role while in others they may be less important.

Finally recommendations are made for fracture design to account for the presence of these IU fractures. These recommendations have a large impact on important decisions such as well spacing, fracture spacing, fluid rheology, proppant loading, proppant size and other fracture design considerations. In many instances these recommendations would have been quite different had the presence of IU fractures not been recognized.
A Commercial Evaluation of Refracturing Horizontal Shale Wells
Authors: Indras P. , Blankenship C.
Published: September 2015

Low commodity prices and high costs associated with drilling and completing multistage horizontal shale wells have forced the hand of many US independent E&Ps. Firms are curbing new drilling activity in shale plays and instead are focusing on improving project efficiencies and controlling cash flow. Refracturing programmes are gaining momentum as it costs less to restimulate a producing wells versus drilling an entirely new well.

Despite the bullish view some players have about refracturing, uncertainty remains surrounding the well selection process and the long-term commercial success of refracs. This paper seeks to address this uncertainty by assessing the economic performance of refracturing programmes in three well-developed shale plays - the Bakken, Barnett and Haynesville.

Sensitivity analysis shows that refractured wells, in the Bakken and Haynesville in particular, can generate higher Net Present Value (NPV) than drilling a new well. Refractured horizontal wells in the Barnett, in contrast, show evidence of reduced recoveries and in some cases even value erosion.

Our analysis of historically refractured wells in the Bakken, Barnett, and Haynesville also leads us to believe that the variation in outcomes is too wide for refracturing to be adopted on a large scale today. While some restimulation events indeed have a profitability index (P/I ratio) larger than a new well, others (even in the same play) generate very poor economics. We believe that technology will play a key role in making this asset management approach more common, particularly in decreasing the number of failed restimulation attempts.
Extending Openhole Gravel Packing Capability - Initial Applications of Alternate Path Openhole Shunt Packers to Provide Upfront Zonal Isolation
Authors: Barry M.D. , Hecker M.T. , Arnold S.P. , Barrilleaux S.J. , Sweeney C.M. , Siegman M.J.
Published: September 2015

Openhole gravel pack (OHGP) completions are often selected as the preferred completion technique to provide long life, high capacity, low skin completions. One drawback to OHGPs, however, is the inability to isolate undesirable water or gas within the completion interval whether it is identified during the initial completion or during any point in the production lifecycle of the well. With the recent introduction of a broad suite of Alternate Path® Technology (APT) tools, the added functionality of true openhole zonal isolation can now be combined with the reliability of gravel packing to deliver unparalleled, long-term completion capabilities.

With the advancement of the new openhole shunt packer with APT, wells have been successfully completed to provide capability for future isolation depending on production results of the well. The shunt packer can be run through 9⅝-in casing, set before gravel packing begins, and form a seal against the borehole to provide annular isolation in either round or oval hole sizes up to 10¾-in. These openhole packers have been recently combined with shunted blank joints to provide upfront isolation of unwanted water or gas found while drilling the completion interval to increase well production rate and/or estimated ultimate recovery (EUR).

This paper will describe the first installations of the equipment which combined internally shunted sand screens, openhole shunt packers, and shunted blank pipe to fully isolate water and gas sands within a completion interval while enabling a full gravel pack across the remaining completion.
Managing The Production Lifecycle: A Framework For Scalable Digital Oilfield Implementations
Authors: Gyara Sunitha , Purwar Suryansh , Bravo Cesar , Sarah Queen
Published: September 2015

This paper describes the expanded value of the digital oilfield (DOF) that is made possible by a flexible IT architecture. The architecture is designed for smarter E&P solutions and can cater to an ever-growing appetite for quick, efficient, and proven solutions to diverse productions and operations industry challenges throughout the production lifecycle.

Investments made in early DOF projects have shown an individualistic flavor with unique architecture, approach, tools, standards, and practices without due consideration for scalability and extensibility. Such customized solutions slow down the adoption of good features from one project to other. Typical examples include customized workflows, a lack of open and service-oriented architecture, and a non-standards-based database or application interface. Partly, this could arise because of lack of experienced and skilled resources, gaps in technology, or the absence of any direct or related analogues to the specific problems of the project.

The following IT architectural components are necessary to enable the flexibility that modern DOF projects need to drive returns: A comprehensive production data-management layerAn engineering modeling suiteA petro-technical workflow automation engineAn analytics library and engineAn advanced visualization and collaboration environment

The success of the flexible IT architecture hinges on proper definition, documentation, optimization, and standardization of business processes for all DOF workflows. This ensures the quality and efficiency of repeatable tasks across applications and domains. For this reason, a services-led architecture is critical.

This paper presents a framework for how DOF solutions should be implemented to enable scalability and maximum impact on business profitability. The standardization proposed reduces non-value-adding time during a DOF implementation and improves the companies' long-term ability to make smarter and faster decisions.
Overcoming a Cementing Failure: Sequenced Fracturing Technique for Remedial Application
Authors: Rainbolt Michael F. , Zakharchenko Sergey , Zheng Wei , Oussoltsev Dmitri , Dunaeva Anna , Clark Brian D.
Published: September 2015

The Cottage Grove formation is an active U.S. mid-continent play where cemented horizontal wells are traditionally stimulated by fracturing several perforation clusters simultaneously using limited entry “perf and plug” or other multi-stage completion solutions. Leaving sections of the lateral unstimulated when fracturing over a large interval can be even more severe in un-cemented completions, where the limited entry technique cannot be relied on to distribute the flow of stimulation fluids in the reservoir. Prior to the introduction of the sequenced fracturing technique, there was no solution to reliably stimulate a large un-cemented or openhole sections. This lead to potential losses of EUR in those wells where for some unplanned event, a section of the wellbore cannot be cemented or isolated with plugs. Recently, a well was drilled and unforeseen issues resulted in 3,300 feet of casing with a completely un-cemented annulus. A remedial cement job was not a feasible option and was quickly dismissed. It was decided to use a new sequenced fracturing technique to complete the stimulation without compromising EUR. This technique uses degradable fibers and multi-sized particles as a composite pill to temporarily plug the fractures and divert stimulation slurry to other regions along the wellbore. In this instance, 20 fracturing stages separated by 12 composite pills and 9 bridge plugs were pumped in sequence to optimize the number of fractures along the wellbore and maximize production.

A production and radioactive tracer log run after the operation revealed that the composite pill successfully diverted the treatment fluids from areas previously fractured to previously unstimulated portions of the lateral. As a result, the entire lateral which had been left without cement was ultimately evenly stimulated. This was confirmed by a production log which showed a constant increase in oil and gas production compared to reference wells. Two hundred and six days after the well has been put on production, the well productivity has been more than 30% higher than any offset well.

The design, execution and job evaluation of the treatments are detailed in this paper, and highlight the keys to the successful treatment which turned a well initially thought to be a failure into a technical and economic success.
Practical Considerations for Production Forecasting in Unconventional Reservoir Systems — Processing of Large Group of Wells Using Production Diagnostics and Model-Based Analysis
Authors: Collins P. W. , Ilk D.
Published: September 2015

Production forecasting in unconventional reservoir systems is not an easy task and should not be soley accomplished using empirical decline curve analysis. Advanced analytical and numerical models have facilitated the analysis of unconventional systems; however, it is almost always impractical to analyze and forecast hundreds of wells using these techniques. The focus of this work is to demonstrate a practical and timely methodology using model based production analysis as the foundation for the analysis and forecasting of each producing well in a particular area/field in an unconventional reservoir. The methodology is founded on a thorough diagnostic assessment of all available data, thorough production analysis of key wells, and extension to the remaining wells using key information from the diagnostic analysis.

The methodology includes three main components: production diagnostics, model-based analysis for representative wells, and production forecasting. Production diagnostics is performed on a single well basis to identify flow regimes and performance metrics of each well, and performed on a multi-well basis to compare performance and identify characteristic behavior which can lead to well groupings and the selection of representative wells for analysis. Representative well(s) from each group are analyzed using model-based analysis incorporating non-linear behaviors associated with the production performance. A systematic analysis procedure is followed to account for the uncertainty on well/reservoir parameters affecting production behavior by utilizing an experimental design methodology. Multiple history matches are obtained accounting for uncertainties such as drainage area, permeability, etc.

Following model-based analysis, production forecasts are developed for the corresponding history matches. Based on either a statistical distribution of EUR values or a deterministic approach, characteristic low/mid/high time-rate profiles can be derived. These profiles are extended to other wells via scaling factors to determine EUR values. Coming full circle, the scaling factors are then compared to well/reservoir data using maps and cross plots of performance metrics obtained from diagnostics to aid in the performance based analysis of the group.