bluuebunny/crossref_metadata_2025 huggingface dataset:
Overcoming Drilling Challenges in the Marcellus Unconventional Shale Play Using a New Steerable Motor with Optimized Design
Authors: Davila Wilfredo , Azizov Azar , Janwadkar Sandeep , Jones Anthony , Fabian John , Rowan Tom
Published: March 2012

Although drilling horizontal wells in US-land unconventional shale plays has increased exponentially in the last few years, maximizing well productivity and improving drilling efficiency remains a major challenge. Well placement in the sweet spot and extended laterals help maximize productivity. Drilling a curve with higher dogleg severity (DLS) reduces its verticalsection and maximizes the length of subsequent lateral section in the productive zone. Wells in US shale plays demand a DLS of 10 to 14 deg/100 ft, but achieving high DLS presents numerous drilling challenges: rotating a steerable motor with a high adjustable kick-off sub (AKO) angle could result in bottomhole assembly (BHA) fatigue failure and premature damage to bit; drilling in oriented mode limits the transfer of weight to the bit, reducing the rate-of-penetration (ROP).

These challenges led to the development and successful testing of a new steerable optimized design motor (ODM) with a short bit-to-bend (BTB) distance. In some cases, the ODM drilled all sections, including high-DLS curves, tangents and laterals with precise directional control and well placement with one BHA. Using the ODM helped the operator achieve higher build rates at lower AKO angle settings; rotate the BHA in well profiles where previously used motors could be operated only in slide mode, and maximize the length of curve interval drilled in rotary mode at higher rotations per minute (RPM). The new system significantly improved drilling performance with excellent directional control. Drilling high-DLS curves increased the length of laterals, enabling additional recovery of gas.

This paper discusses the design, modeling and results of horizontal type wells drilled using the steerable ODM in the Marcellus unconventional shale play.
Lab NMR Study on Adsorption/Condensation of Hydrocarbon in Smectite Clay
Authors: Zhang Jillin , Chen Jin-Hong , Edwards Carl
Published: March 2012

Significant amounts of gas accumulations exist in unconventional gas plays. Current understanding held that in unconventional shale plays, natural gas was stored as "free" gas in pore spaces and as an "adsorbed" phase on clay minerals and surface of organic pores material. The adsorption of methane has been confirmed in lab experiments in high-pressured gas chambers. Our lab experiments indicated that hexane vapor could be adsorbed onto organic-rich shale core samples through capillary condensation and the signal could be detected by Nuclear Magnetic Resonance (NMR) instruments. This study further examines the capillary condensation of hexane vapor into clay minerals and the NMR response.

Smectite samples from the Clay Minerals Society were used in the experiments. Two types of capillary condensation experiments were conducted: one with water vapor and the other with hexane vapor, both at room conditions. Weight gains indicated that some of the vapor condensed in the loose powder of smectite clay. NMR experiments were performed on vapor-saturated samples using a Maran 2 MHz spectrometer with an inter-echo time of 300 μsec.

The T2 distributions of the water-vapor and hexane vapor-saturated smectite clay were both unimodal. The water vapor-saturated sample showed a T2 at 0.5 ms, while the hexane vapor-saturated sample showed a T2 between 1 and 6 ms. This was likely due to the fact that the smectite crystallites have a small charge that has a more pronounced effect on polarized molecules such as water, than on non-polarized molecules such as hexane.
Silurian Lithofacies and Paleogeography in Central and Eastern Europe: Implications for Shale Gas Exploration
Authors: Tari Gabor , Poprawa Pawel , Krzywiec Piotr
Published: March 2012

The present day collage of various Silurian basin fragments in Central and Eastern Europe is the result of several orogenic and rifting/drifting episodes. The proper paleogeographic reconstruction of a single, very large Silurian foredeep basin in the context of regional geology has a major impact on the ongoing unconventional shale gas exploration efforts in the broader region.

The distal segments of a large Silurian foredeep basin, as the result of Caledonian orogeny, can be reasonably followed along strike from NW to SE, from Poland to Ukraine and Moldavia, all the way to the Black Sea coast. The foredeep basin sequence is onlapping to the NE on top of various Lower Paleozoic and basement units. The flexural origin of the basin, besides the typical subsidence curves, is also supported by the distribution of lithofacies such as deepwater shales in the center, neritic carbonates on the foreland perimeter and clastic turbidites on the southwestern flank.

The proximal parts of the Silurian basin are much harder to reconstruct. Two major opening episodes are critical for restoring the Silurian paleogeography. One of them is the reconstruction of the conjugate Bohemian (Austria, Czechia, Slovakia and Poland) and Moesian (Romania and Bulgaria) passive margins prior to the opening of the Jurassic Magura Ocean. The other important step for any regional-scale Silurian reconstruction is the closing of the Cretaceous western Black Sea Basin between the conjugate margins of Moldavia/Romania/Bulgaria and Turkey.
Novel Traceable Proppant Enables Propped Frac Height Measurement While Reducing the Environmental Impact
Authors: Saldungaray Pedro , Palisch Terry , Duenckel Robert
Published: March 2012

Fracture height is typically used by fracturing engineers to calibrate propagation models. Having an accurate height measurement reduces the uncertainty and non uniqueness of fracture pressure matching, better determining placed frac length and width, stress profile across the target zone and its boundaries, and fracture containment. This is particularly important when there is concern with vertical penetration into an unwanted zone, or determining adequate zonal coverage and development of reserves.

In most cases, fracture height is measured by the industry through the use of radioactive tracers which are blended into the proppant at the wellsite. Clearly this can present both a safety and environmental hazard. Furthermore, in some regions of the world operators are prohibited from using these hazardous materials altogether.

This paper presents an innovative, environmentally responsible proppant detection technology and the associated logging techniques for propped height measurement and/or proppant placement. Its non-radioactive nature eliminates the risks and difficulties inherent to other tracing methods. Furthermore, being inert the proppant has no half-life time limitation and is permanently detectable. In this manner it provides the flexibility of conducting multiple post-frac logging at any time after fracturing for initial assessment or to identify intervals for re-stimulation further down the life in the well. The tracing capability doesn’t interfere with the proppant physical properties, crucially its strength and conductivity, assuring adequate performance.

The theory and physical principles of the technology are discussed in detail and supported by case histories of its application in various environments around the world.
The Challenges of Shale Gas Exploration and Appraisal in Europe and North Africa
Authors: Burns Christopher , Topham Adrian , Lakani Ramin
Published: March 2012

The shale gas revolution on North America has created an incentive for the rest of the world to chase this challenging hydrocarbon resource. Currently around 44% of the 20.6 tcf annual gas production in the US occurs from unconventional resources, with this forecast to rise to 65% by 2020. The pitfalls and challenges faced by North American development projects provide a wealth of experience, which can be used to understand how we can apply technology more effectively in Europe and North Africa. However, there are differences in both operating environments and gas markets between North America and Europe and North Africa, and we aim to highlight these differences as well as the similarities. Unconventional oil and gas projects in Europe and North Africa are currently at an early stage of their life cycle, exploration and appraisal. We identify the following key challenges for the European region: The potential spread of the North American unconventional gas revolution to Europe and North Africa could create competition and depress gas prices. Reduced gas prices and increased costs will considerably reduce the margin for error in exploring for unconventional gas. Therefore there is a need to apply technology effectively, to avoid having to learn "by the drill bit".A lack of infrastructure and specialised equipment, particularly in North Africa, leading to a higher cost base for developing the region’s unconventional resources.The regulatory environment in Europe is not presently conducive to development of shale gas resources together with the negative public perception of the environmental risk associated with shale gas development.

Aside from these medium to long term challenges, Europe at present is facing a more critical short term challenge: the need to prove the concept by completing and producing the first economic shale gas wells.

To overcome these challenges, operating and service companies need to apply technology effectively and efficiently at an early stage in shale resource development. This paper offers a potential approach and methodology first to evaluate unconventional resources, and secondly to apply technology to unlock their potential. An integrated oilfield service approach could make unconventional gas appraisal outside of North America economically feasible and sustainable. As in conventional reservoir developments, detailed reservoir description can be used to optimize reservoir penetrations and predict well performance. In the second part of this paper we discuss how a Shale Engineering workflow that will improve the effectiveness of interaction between operators and service companies, and enable commercial production of unconventional resources outside North America.

Unconventional reservoirs are defined for the purposes of this paper as oil and gas reservoirs that exhibit low permeability such that hydrocarbons cannot be produced at economic rates without stimulation of the reservoir.
Understanding Volumes, Economics and Risk Mitigation in Unconventional Gas Projects
Authors: Giles Melvyn R. , Nevin Daniel , Johnston Bud , Hollanders Mark
Published: March 2012

A great deal has been written on the volumes of unconventional gas trapped in the subsurface, this paper examines: The relationship between the huge GIIP volumes, technically recoverable volumes and economically recoverable volumesThe barriers to achieving economically viable projectsLifecycle and drivers for creating economically viable projectsThe use of decline curves to estimate the productivity and the pitfalls associated with their useStrategies for mitigation of economic risk in taking an exploration project through to development

New unconventional gas projects all come with considerable uncertainties and therefore risk, but careful de-risking strategies enable companies to steer their way toward clear go/no go decisions at multiple points in the lifecycle enabling them to progress with minimum exposure.
Integrating Geology, Hydraulic Fracturing Modeling, and Reservoir Simulation in the Evaluation of Complex Fluvial Tight Gas Reservoirs
Authors: Ramirez Kelly M. , Cuba Patricia H. , Miskimins Jennifer L. , Anderson Donna S. , Carr Mary M.
Published: March 2012

Hydrocarbon resources such as tight sands have become one of the most sought after types of unconventional plays, given the extensive amounts of gas they contain. In order to access these reserves, the industry is focused on improving hydraulic fracturing techniques with the purpose of increasing gas recovery. However, proper reservoir management practices, in conjunction with improved completion processes, are also key factors for maximizing these gas reserves. Additionally, reservoir understanding becomes even more relevant when dealing with reservoirs deposited in complex fluvial environments.

This paper discusses a study that integrates the accurate stratigraphy and detailed reservoir characterization of a 160-acre 3D fluvial geologic outcrop model populated with analog producing field reservoir properties with detailed hydraulic fracturing modeling to better understand the effects that fluvial depositional environments have on hydraulic fracture growth. Subsequently, the detailed hydraulic fracturing growth parameters are implemented in a robust 3D reservoir simulation model, representing the heterogeneous geologic environment. Reservoir simulation is then used to determine the dynamic flow conditions associated with the fluvial geologic model with the ultimate goal of determining optimum reserve recovery practices such as well spacing and placement, hydraulic fracture design components, etc.

The methodology applied in this study, which starts with the 3D outcrop mapping and characterization, followed by the development of a geostatistical model, hydraulic fracturing modeling, and reservoir simulation is presented. Three different cases, consisting of various well locations and spacing, are described. Results show that the continuity of sand bodies in the near wellbore vicinity, whether part of the completion interval or not, is critical to the ultimate reserve recovery and is a function of the hydraulic fracture growth pattern. Additionally, amalgamation of the sandstone bodies, which also affects the hydraulic fracture growth patterns, has a strong effect on gas recoveries. Finally, for the cases reviewed, the benefits of infill drilling were mainly obvious in reserve acceleration versus reserve addition.
A New Approach to Biocide Application Provides Improved Efficiency in Fracturing Fluids
Authors: Dawson Jeff , Wood Marodi
Published: March 2012

Hydraulic fracturing of oil and gas wells requires high volumes of water. Often these waters originate from rivers, lakes, ponds, and recovered water from previous fracturing treatments. These waters are often infested with aerobic and anaerobic bacteria that can cause multiple problems. These include degradation of fracturing chemicals, down-hole corrosion, biological-based H2S generation, and down-hole flow-impairment due to slime producing bacteria. Historically, these waters have been treated with biocides such as tetrakis (hydroxymethyl) phosphonium sulfate (THPS), glutaraldhyde or quaternary ammonium-based surfactants. Lately, oxidizing biocides such as peracetic acid, chlorine dioxide and hypochlorous acid have been used as environmental alternatives.

Recently, tetrahydro-3,5-dimethyl-l,3,5-thiadiazine-2-thione (Dazomet) has been used as a biocide with good results in the Barnett, Marcellus, Eagle Ford and Haynesville gas shale basins in the US. This biocide is effective against most aerobic and anaerobic bacteria encountered in water sourced for fracturing applications. Although not a fast-killing biocide, it is effective for long-term maintenance of the formation and well with loadings normally about 0.4 L/m3 of 24% active solutions.

Further investigation has now discovered that the combination of this biocide with others has significantly reduced necessary loadings of these biocides to values less than 0.2 L/m3. These Dazometcombinations also tend to show much higher degrees of efficacy, showing superior bacteria management over the single or oxidizing biocides. This enhanced performance also allows for reduced chemical exposure to the environment. The performance of these Dazomet biocide-combinations and field trials will be presented and discussed.
Advances in Measurement Standards and Flow Properties Measurements for Tight Rocks such as Shales
Authors: Sinha S.. , Braun E. M. , Passey Q. R. , Leonardi S. A. , Wood A. C. , Zirkle T.. , Boros J. A. , Kudva R. A.
Published: March 2012

Determination of permeability of unconventional reservoirs is critical for reservoir characterization, forecasting production, determination of well spacing, designing hydraulic fracture treatments, and a number of other applications. In many unconventional reservoirs, gas is produced from tight rocks such as shale. Currently the most commonly used industry method for measuring permeability is the Gas Research Institute (GRI) technique, or its variants, which involve the use of crushed samples. The accuracy of such techniques, however, is questionable because of a number of inadequacies such as the absence of reservoir overburden stress while conducting these measurements. In addition to questionable accuracy of crushed rock techniques, prior studies have indicated that there is significant variability in results reported by different laboratories that utilize crushed-rock technique to measure permeability on shale samples. Alternate methods are required to obtain accurate and consistent data for tight rocks such as shales. In this paper we discuss a robust steady-state technique for measuring permeability on intact tight rock samples under reservoir overburden stress. Permeability measurement standards for low permeability samples are critical for obtaining consistent results from different laboratories making such measurements, regardless of the method used for measuring permeability. In this paper we present permeability measurement standards developed based on first principles that serve as the "ground-truth" for permeability in the 10 – 10,000 nanoDarcy range. These standards can be used to calibrate any permeability measurement apparatus used to measure permeability on intact tight rock samples such as shales, to enable delivery of consistent results across different laboratories conducting measurements on intact tight rock samples.
Assessment of an Unusual European Shale Gas Play: The Cambro-Ordovician Alum Shale, Southern Sweden
Authors: Pool Wilfred , Geluk Mark , Abels Janneke , Tiley Graham , Idiz Erdem , Leenaarts Elise
Published: March 2012

In 2008 Shell obtained two licenses for unconventional gas exploration in the Skåne region of southern Sweden, with a total size of 2500 km2 (600,000 ac). The objective was the Cambro-Ordovician Alum Shale, one of the thickest and richest marine source rocks in onshore northern Europe.

The licenses covered the Höllviken Graben and the Colonus Shale Trough. In both areas the Alum Shale had been encountered in older wells, with a thickness of up to 90 m and TOC values up to 15%. Maturities of up to 2% Vre were considered encouraging for a shale gas play. Relative high quartz contents suggested good fraccability of the shales. All data was obtained through public sources. Identified risks were the uncertain timing of hydrocarbon generation and the position of the licenses adjacent to the Trans-European Suture Zone where several phases of fault movement have a risk for actually retaining the hydrocarbons.

The derisking strategy for this opportunity was based on both technical and non-technical aspects. Aim was to collect geological and geophysical data to constrain depth and thickness of the shale and to identify potential dolerite dykes. In addition, well data were needed to establish rock properties and gas content. The external environment, especially concerns from the people in Skåne regarding the visual impact of activities and potential impact of drilling activities on the aquifers and on the tourism industry have resulted in extensive engagements with stakeholders and specific requirements around seismic acquisition (low impact), site preparation and operations (e.g. small rig, different lighting).

80 km of 2D seismic was acquired in 2008 and three wells, with a final depth of around 1000 m, were drilled in 2009 to mid 2010. The Alum shale was fully cored and the well sites have been restored. Thickness, richness and maturity of the Alum were as predicted although the basin was shallower than previously anticipated. Canister desorption tests, however, indicated that the shales have only low gas saturation. This significantly increased the risk for a viable shale gas play and therefore the licenses were not renewed after the initial 3 year period.
Benchmarking Unconventional Well Performance Predictions
Authors: van den Bosch Rainer , Paiva Antonio
Published: March 2012

The hydrocarbon industry is constantly challenged to improve subsurface description and operating practices to maximize returns on capital employed. Well locations are typically identified by continuously improving the geologic and reservoir engineering modeling. As a consequence, and on an on-going basis, refinements in drilling and stimulation practices are introduced based on a better understanding of rock and fluid interaction.

However, over the near term it is difficult to validate the impact of changing processes. It takes typically several months before stabilized flow conditions are established such that well performance can be determined with confidence from decline curve analysis. Moreover, it takes several years before robust and reliable estimated ultimate recovery (EUR) predictions can be made. Hence, the findings are obtained often too late to influence ongoing unconventional field development, especially in manufacturing pad development that is characterized by high levels of drilling and completion activities.

In this work we propose a benchmarking system that enhances the forecasting of long-term well performance, based on metrics of short-term well behavior. The metrics are routinely recorded from the first day of production such as peak month production or 3, 6, 12 and 24 month cumulative production. The process is refined continuously as and when new information becomes available and the added value of the information is quantified. A new key performance indicator (KPI) condenses the range of predicted outcomes into a single number via a simple numerical function that allocates increasing cost for increasing misclassification. The range is 0% = no predictive capability of the system to 100% = perfect predictive capability of the system. This approach enables a transparent and unbiased benchmarking of the system’s prediction capability for each metric.

In adding to the analytical toolkit, the key objective of this benchmarking method is to support decision making on an ongoing development, well before the entire program has been executed. Possible applications include: Early confirmation of successful well placement.Early indication of the impact on well performance as a result of changes to drilling and stimulation procedures.A ‘conditional probabilistic’ outlook of long-term well behavior to better define well/field economic scenarios and to guide reserve bookings.

This process has been developed using public data from the data rich fields Barnett in Texas, Fayetteville in Arkansas and Woodford in Oklahoma. This process is also viable for plays with scarce data and is able to be refined with increasing data availability.
Understanding Hydraulic Fracture Stimulated Horizontal Eagle Ford Completions
Authors: Shelley Robert , Saugier Luke , Al-Tailji Wadhah , Guliyev Nijat , Shah Koras
Published: March 2012

This paper will present results from a modeling effort to derive best practices for the completion of hydraulically fractured horizontal Eagle Ford wells. The well, reservoir, completion/frac and production information used in this evaluation were provided by an operator from a five-county area in Texas.

Hydraulically fractured horizontal completions pose significant modeling and evaluation challenges. This is primarily due to two issues: 1) lack of well-specific data about the reservoir/rock properties, and 2) improper assumptions used in the modeling process. As shown in this paper, a data-driven approach to modeling these completions provides a much needed pragmatic perspective, identifies high-impact parameters and provides direction about how to improve the effectiveness of these complex completions.

Sensitivities performed on the predictive data model indicate that well-to-well variation in reservoir quality and geology has a dominant effect on Eagle Ford production. In addition, issues such as fracture spacing, frac volume, perforation distribution, proppant selection and wellbore length also affect well production and economics. A summary of completion and frac methodology for the Eagle Ford, in addition to a ranking of controllable (completion and frac design) and non-controllable (reservoir and geology) parameters that affect Eagle Ford production, will be included in this paper.

The information contained in this paper will be useful to those interested in reservoir, completion and frac parameters that affect production from shales analogous to the Eagle Ford. Reservoir quality, completion and frac methodology effects on production results will be quantified in this paper.
Visualizing Stress Trajectories around Hydraullicaly Pressurized Wellbores
Authors: Weijermars Ruud , Schultz-Ela Dan
Published: March 2012

A new approach, using stress functions, reveals how each component of the stress regime affects the stress pattern around the wellbore. The effect of tectonic far field stress on the stress trajectories in the host rock near a wellbore is visualized in a series of plots with the analytical stress trajectory solutions for a large range of net pressures on the wellbore. The deviatoric stresses around a wellbore result from the dynamic superposition of (1) far field tectonic stress, (2) near wellbore stress due to lithostatic pressure near the open hole, (3) pore over-pressure or under-pressure in the host rock, and (4) hydraulic pressure applied on the wellbore. The principal stress trajectory plots are used to determine the suitable options for well orientations and to delineate stress trajectory control of the incipient brittle failure patterns for hydrofracs and wellbore breakouts. Our approach provides fundamental insight, with an important practical application for improved understanding of the growth of hydrofractures.
Exploring Shale Basins using Existing Wells
Authors: Pitcher Jason , Kwong Shan , Yarus Jeffrey , Mullen Mike
Published: March 2012

In the search for unconventional shale plays with commercial potential, many operators have properties in petroprovince basins containing wells through potentially productive shale zones. These shales were often encountered as part of exploration or development programs for deeper conventional targets. Often, the overlying shale is known to have had gas or oil shows reported during initial drilling, but little or no additional geological data was acquired at the time.

This paper discusses the workflow and method to use the minimal information from these existing wells, and to quantitatively incorporate them into a basin exploration program. The process begins with a single new well, such as a sidetrack from an existing well, which is evaluated with the full array of open hole logging tools. Coring (conventional or sidewall), DFIT tests, and other shale-specific logging tools are performed on this initial well. Pre-existing wells that penetrate the objective shale can also be quantitatively assessed for relevant shale properties by using specialized logging tools, such as a combined through-casing pulsed neutron and sonic tool, to map relevant shale properties. These tools are calibrated to the open hole data to generate a wider distribution of data points containing critical shale properties that can be demonstrated to have a strong relationship with production.

After the data acquisition process has been performed, the data are combined with existing seismic and structural information to delineate the best areas for further evaluation. Using modern mapping tools, a basin can be rapidly appraised to identify sweet spots, providing further exploration targets for evaluation drilling.

This paper discusses limitations, best practices, workflows, and methods, and includes an example of a European shale evaluation log to demonstrate this exploration technique.
Microseismic Monitoring of Fracture Networks During Hydraulic Stimulation: Beyond Event Locations
Authors: Kendall J-M.. , Verdon J. P. , Baird A.. , Wuestefeld A.. , Rutledge J. T.
Published: March 2012

The successful exploitation of tight-gas reservoirs requires fracture networks, sometimes naturally occurring, often hydraulically stimulated. Borehole microseismic data acquired in such environments hold great promise for characterising such fractures or sweet spots. The loci of seismic events delineate active faults and reveal fracture development in response to stimulation. However, a great deal more can be extracted from these microseismic data. For example, inversions of shear-wave splitting data provide a robust means of mapping fracture densities and preferred orientations, useful information for drilling programs. They can also be used to track temporal variations in fracture compliances, which are indicative of fluid flow and enhanced permeability in response to stimulation. Furthermore, the frequency-dependent nature of shear-wave splitting is very sensitive to size of fractures and their fluidfill composition. Here we demonstrate the feasibility of using such analysis of shear-wave splitting measurements on data acquired during hydraulic stimulation of a tight-gas sandstone in the Cotton Valley field in Carthage, West Texas.
Can We Achieve Acceptable Fracture Conductivity Using WaterFracs?
Authors: Mcdaniel B. W.
Published: March 2012

After 1970, the technology of hydraulic fracturing began to quickly accelerate, especially as to the industry focus on fracture conductivity. We saw a transformation in our frac fluids as we moved away from crudes and thin water gels to higher viscosity emulsion systems, foamed gels, and even crosslinked gel systems that could deliver significantly more proppant as we chased after better fracture conductivity. Using these more viscous gels we moved to "Massive Hydraulic Fracturing" of tight gas sand formations. This grew to multi-million pound proppant placements as the age of crosslinked gels began to dominate most of the fracture stimulation landscape as we tried to place very long, highly conductive fractures. However, the decade of the 1970’s also had Claude Cooke showing us that sand was a very limited proppant for deeper wells, and then later showing that gel residue could seriously reduce insitu fracture conductivities! (Cooke 1973; 1975; 1976; 1977) During the early 1980’s North America experienced the greatest rig activity ever, but then the mid-80’s gave us the greatest crash the oilfield had ever seen! Fortunately, this also resulted in our industry laboratories having the time to upgrade testing equipment and procedures to "realistic" test conditions for evaluation of packed proppant bed conductivity. This meant longer testing times, high temperatures, and with exposure to frac fluids. This research would subsequently launch the search for better gel breakers and lower residue gels (which continues today).

Unexpectedly, in the 1990’s a few operators in tight sandstone applications in East Texas started re-inventing Slick Water fracs (WaterFracs), placing only 15-20% as much proppant as crosslink gel fracs, yet claiming equal or better overall economics. To add further consternation, George Mitchell found another application for WaterFracs and eventually showed the world that a hydrocarbon-source shale formation, the Barnett, can actually be a commercial producer itself. During the early 2000’s, the combination of long horizontals, and extreme multi-stage hydraulic fracturing (mostly using Waterfracs) turned the Barnett Shale into the launching pad of our present-day madhouse search for the next great shale play to chase.

It is clear that long horizontal completions and WaterFrac stimulation methods have played an important role in opening the door to economic success in the numerous "resource plays" (i.e. shales). In this paper we will investigate if WaterFrac treatments are violating or upholding (?) one of our most significant fracturing beliefs: Fracture Conductivity should be optimized. Until we moved to the ultra-low formation permeabilities, we would generally say we should try to maximize our conductivity, but with WaterFracs designs it often seems we may instead be minimizing it, and this will be discussed here.
Experimental Measurements of mechanical parameters of Class G cement
Authors: Teodoriu Catalin , Yuan Zhaoguang , Schubert Jerome , Amani Mahmood
Published: March 2012

The new quest of unconventional resources is the achievement of well integrity which is highlighted by the inadequacy of conventional cementing procedures to provide zonal isolation. High temperatures and pressures or even post-cementing stresses imposed on the cement sheath as a result of casing pressure testing and formation integrity tests set in motion events which could compromise the long term integrity of the cement sheath due to fatigue. Knowledge of the mechanism of fatigue in cement and factors that affect it such as the magnitude of the load, strength and composition of the cement, mechanical properties of the cement and pattern of load cycles are important to achieve a realistic design of a cement system that will be subjected to fatigue loading. Such a design will go a long way to ensure the long term integrity of a well operating under downhole conditions. Finite element investigations help engineers to assess the stress magnitude and evolution for a given well configuration, but when structural calculations for casing-cement system are required, missing input parameters reduce the quality of the results.

In order to have reliable data we performed an extensive experimental work using Class G cement in order to measure the principal parameters for mechanical structural calculations: compressive and tensile strength, Young modulus, Poison Ratio. The data was measured under room conditions and elevated temperature and pressure. The results were also extrapolated for a time period for more than 300 days.

The paper will provide an excellent data inventory for class G cement that can be used when mechanical studies on cement, like finite element studies, are required.
Non-Conventional Plays in Romania: the Experience of OMV Petrom
Authors: Krezsek Csaba , Lange Simon , Olaru Radu , Ungureanu Cristina , Namaz Pervin , Dudus Roxana , Turi Valentin
Published: March 2012

This paper describes the key findings of a regional study that targeted the unconventional potential of exploration assets hold by OMV Petrom in Romania. Three unconventional plays have been evaluated, including the (1) Silurian and (2) the Dogger on the East European Margin (including Moesia), and the (3) Oligocene in Maramures (Pienides). The Silurian shales are at 2-4 km depth in the gas window on Western-Central Moesia. Maturity in most cases has been reached by the Late Paleozoic and it was followed by significant exhumation during the Hercynian Orogeny. The quality of Silurian shale represents a major uncertainty, due to the sparse dataset represented by old wells. The Dogger shales of Northern Moesia are in the oil and gas window under the most external thrusts of the Carpathians at depths that exceed 4 km. The shales have TOC values up to 6 %. Oligocene shales with TOC of up to 10 % in Maramures are in the oil window at depths of less than 2 km. This makes them a very attractive target for shale-oil exploration. However, major setbacks are the complex tectonic structure, rugged topography and large-scale exhumation. Ongoing exploration efforts for non-conventional plays are targeted to define the mechanical properties and the exploration sweet spots in the above mentioned plays, but also assessing the potential of the Late Paleozoic bituminous dolomites of Moesia and other black shales in the Carpathians.
Identifying Fault Activation in Unconventional Reservoirs in Real Time Using Microseismic Monitoring
Authors: Kratz Michael , Hill Andrew , Wessels Scott
Published: March 2012

Identification of fault related microseismicity in hydraulic fracture treatments is crucial to understanding how treatments are stimulating a reservoir. Evaluating b values in combination with event source mechanism provides a reliable and intuitive method for separating fault related microseismic events from standard fracture related events. Typically this analysis is conducted after a treatment is complete and serves as a diagnostic tool to provide possible explanations for reduced production or designing future treatments on nearby wells to avoid an identified fault feature. Being able to identify such features in real time allows the operator to not only identify faults but to stop treatment and avoid these features all together saving time and materials that would otherwise be pumped into an area that doesn’t contribute to the overall stimulation of the reservoir, and could reduce production on the well. When evaluating b-values in real time, a technique that can identify faulting early in the initiation of fault stimulation is crucial for preserving the most resources during treatment.
Cyclic Shut-in Eliminates Liquid-Loading in Gas Wells
Authors: Whitson Curtis Hays , Rahmawati Silvya Dewi , Juell Aleksander
Published: March 2012

This paper presents a method to eliminate production loss due to liquid-loading in tight gas wells. Cyclic shut-in control is a simple production strategy that particularly benefits lower-permeability stimulated wells, including but not limited to shale gas wells.

Comparison is made between a gas well producing (1) in a "ideal" situation where 100% of liquids entering from the reservoir or condensing in the tubing are continuously removed (without shut-ins), (2) in a meta-stable liquid-loading condition with low gas rate, typical of most wells today, and (3) by the proposed strategy of cyclic shut-in control. We show that cyclic shutin control of stimulated low-permeability vertical wells to ultra-low-permeability horizontal multi-fraced wells can produce without ever experiencing liquid loading, and with little-to-no delay of ultimate recovery.

Cyclic shut-in control can be applied to all stimulated, lower-permeability gas wells, from the onset of gas rates that result in liquid-loading. The strategy can also be used for wells which already have experienced a period of liquid-loading, but the expected performance improvement may be less because of near-well formation damage caused by historic liquid-loading – e.g. fresh-water backflow and liquid-bank accumulation. In historically liquid-loading wells, an initial period of liquid removal and/or light stimulation may be needed prior to initiating cyclic shut-in control.

We show that the shut-in period should optimally be as short as operationally possible.

Cyclic shut-in control is shown to work equally well for layered no-crossflow systems with significant differential depletion at the onset of liquid loading.

Minimizing rate and recovery loss of liquid-loading gas wells is of international interest. We believe that cyclic shut-in control will become an industry standard practice for shale gas wells, and should lead to a significant ultimate increase in worldwide gas reserves. The method is extremely simple and requires only a rate-controlled wellhead shut-in device.
Resource Assessment and Fluid Flow in Nanoporous Unconventional Petroleum Systems
Authors: George Szabo , Bada Gabor
Published: March 2012

The resource assessment of unconventional gas accumulations depends on C B"C C conventionalC B"C C methods including the reconstruction of the tectonosedimentary evolution of the given basin, the organic content, the understanding of the subsidence, burial, thermal and maturation history, and the timing and mechanism of hydrocarbon generation. In addition, successful production strategies should rely on "unconventional" approaches. The long path from recognizing the potential to the actual production of such hydrocarbon systems requires understanding fluid flow mechanism in nanoporous rock matrix. It is recognized that Darcy permeability is of limited use when applied to tight rocks with unperturbed, non-fractured, nano-range pore size where the pressure gradient would not enable gas flow. Instead, concentration-driven diffusion as a function of the fracced rock mass surface has critical importance. This process has been recently identified as the main driving force of fluid flow in extremely tight rocks. Besides optimizing production technologies, such as various stimulation techniques, they critically influence reserve estimations through highly uncertain recovery, a key to the ultimate economic assessment of unconventional projects. Experience shows that, when diffusion flow dominates in the rock matrix, even the latest pressure pulse decay permeability test equipment may be insufficient to describe the process. The use of photo-acoustic laser apparatus to measure mass flow is an efficient tool of has enabled resource estimation and proved very helpful in the engineering of frac operations. New laboratory measurements reported in our presentation enables to determine diffusion coefficient under realistic HP-HT and various sorption/desorption conditions, hence allowing production simulation. Case study from the MakC C B3 Trough in the Pannonian basin, Hungary, shows the great potential of this novel methodology. The definition of diffusion characteristics can be used as an aquifer protection technique in conjunction with the stimulation engineering.
Selection Criteria for Tubular Connection used for Shale and Tight Gas Applications
Authors: Teodoriu Catalin
Published: March 2012

An unconventional reservoir poses not only difficulties in producing it economically but also requires constrains about the well construction and tubular selection in order to keep the budget in acceptable limits. The tubular used for well construction and well completion must offer maximum integrity at, if possible, minimum costs for the life of the well. The costs associated with tubular are generated by the steel price plus the connection costs. Use of premium connections may not be justified in all unconventional reservoir applications, but as this study will prove, they offer better solutions when the life if the well is considered.

This paper starts with a review of main tight gas fields worldwide and based on the well analysis a general tendency for well completion will be shown. The second part of the work will focus in analyzing casing design criteria used in afore mentioned fields. As a result a comprehensive discussion about casing and coupling selection for unconventional wells will be generated. Premium versus non premium connections will be discussed and their impact on the life of the well will be analyzed.
Identification, Integration and Upscaling of Mudrock Types - A Pathway to Unlocking Shale Plays
Authors: Spaw Joan M.
Published: March 2012

A multidisciplinary approach to shale characterization in a variety of North American gas- and liquids-rich shale plays has lead to improved understanding of the bulk physical, chemical and mechanical properties of these deposits and their geologic history. This effort is leading to successful exploitation of these enigmatic resources. Microfacies analysis of mudrocks provides a platform for upscaling from the "nano" to the regional scale, and results in comprehensive mudrock characterizations.

Microfacies analysis of mudrock types within a select stratigraphic interval in a basin leads to the recognition of mudrock lithofacies. Lithofacies identification allows for calibration of petrophysical models, documentation of basin-specific variations in mudrock composition and microfabrics, the distribution of organic-rich members of these intervals, definition of the mechanical stratigraphy for completion design, and provides the litho-stratigraphic building blocks for predictive sequence stratigraphic models.

Successful exploration and exploitation of mudrocks as resources can be advanced when the recognition of mudrock lithofacies provides a methodical means to tie together the geologic, chronostratigraphic, geochemical and petrophysical data from a diverse spectrum of physical scales and technical disciplines.
Just-In-Time Perforating for Controlled, Cost-Effective Stimulation and Production Uplift of Unconventional Reservoirs
Authors: Angeles Renzo , Tolman Randy , El-Rabaa Wadood , Jackson Shalawn , Nygaard Kris
Published: March 2012

Recent advances in multi-stage stimulation technologies, including open- and cased-hole types, have largely overlooked the advantages of single-zone stimulation due to hardware and cost limitations. In most conventional methods, multiple perf clusters are treated at once using one single frac stage with the expectation that equally-stimulated fractures will be created at each perf cluster within tens and hundreds of feet. This creates over-stimulation in some perf clusters and under-stimulation in others, which unveils the current economic and practical limits of effectively creating fractures where needed, not where it is possible to place them. Other methods use a large number of frac plugs which require additional wireline trips and later need to be drilled out, increasing the total cost and mechanical risk of the completion. As lateral length increases, many operators also face the challenge of not being able to remove all frac plugs due to coiled-tubing depth limitations.

This paper introduces the recent implementation of Just-In-Time Perforating (JITP) in shale gas, unconventional plays. JITP is one of the Multi-Zone Stimulation Technologies (MZST) developed and patented by ExxonMobil over a decade ago and extensively used in vertical and S-shaped wells in the Piceance basin, Colorado, and recently implemented in the XTO Fayetteville Shale, Arkansas. JITP creates multiple single-zone fracture stimulations on a single wireline run using ball-sealer diversion and perforating guns that remain downhole during fracturing. Other key features of this method are the use of less horse power, significant reduction in the number of frac plugs, fewer wireline runs, and added flexibility in water management. This paper describes the technical advantages and business justification for applying JITP in unconventional resources and also provides preliminary results from the performance of the JITP field trials in horizontal wells.