bluuebunny/crossref_metadata_2025 huggingface dataset:
Distributed Acoustic Sensing for ESP Understanding and Surveillance
Authors: Allanic C.. , Frangeul J.. , Liebeck M.. , Carbonnier B.. , Naldrett G. J. , Farhadiroushan M.. , Clarke A..
Published: June 2014

Distributed Acoustic Sensing (DAS) technology from optical fibers is already identified as very promising for reservoir monitoring1 and especially for seismic applications2 with many stakes today in all Oil&Gas companies. DAS surveys can also have more "production" oriented applications for in-well surveillance and more specifically in complex well configurations and completions. This paper relates an in-well trial from permanent optical fibers installed in a horizontal, multi-lateral and ESP (Electrical Submersible Pump) activated well.

Two types of fibers had been installed permanently in this well: a multi mode fiber and two single mode fibers linking FBG’s (Fiber Bragg Gratings) optical gauges. These fibers were used to simultaneously acquire distributed temperature from DTS and distributed acoustic data from DAS.

The first objective of this in-well trial was to use the DAS data to improve or better constraint the temperature interpretation to get more reliable flow profiles. The acquisition sequence was designed to generate several temperature disturbances using different ESP frequencies leading to different production rates.

DTS interpretation has been performed and results are now more in accordance with previous interpretations. However, the ESP location introduced noise which made difficult to interpret the DAS signal from the close producing zones. For that reason, the first objective was not fully reached. It should be noticed that this was the first DAS acquisition in a well equipped with an ESP. The paper describes also how DAS data were investigated to open a new application on the understanding of pump behavior and possible optimization of pumps.
Direct Measurement of Gas Content Without Coring
Authors: Gray Ian , Singh Harjeet , O'Brien Andrew
Published: June 2014

This new process enables the quantitative determination of the gas content of coals and other strata, such as shales or conventional reservoir rocks during overbalanced open hole drilling. This paper presents the results of a field trial through coal seams in Central Queensland where the system was tested and showed favourably comparable results to those obtained from gas content measurement by conventional core desorption in coals.

The system involves drilling in overbalanced mode through so that no reservoir fluids enter the well bore. Under these conditions the only material produced is that cut from the hole. This comprises cuttings and may also include gas and liquids contained therein. This material rises up the annulus and is diverted by a rotary seal to a cyclonic separator. This separates the free gas while the mud and cuttings overflow from the base of the separator and over a shale shaker. The free gas volume is measured directly while the cuttings are separated from the mud on the shaker and are sampled into canisters so as to permit measurement of any gas that may desorb from them freely or further after crushing.

The system thus enables the capture and measurement of all gas contained in the drilled strata with the exception of that desorbed during the brief period that the cuttings are on the shaker. This lost gas is small and may be readily estimated. The system is direct and simple and has the potential to replace core sampling and other more indirect and complex geophysical techniques to measure the gas contained in strata.
Research on Fractured Horizontal Wells Productivity and Productivity Influence in Shale Gas Reservoir
Authors: Xie Weiyang , Li Xiaoping
Published: June 2014

Based on large number of shale gas exploration and development literature research, this paper describe the characteristics, accumulation regularity, adsorption and desorption properties of shale gas which are different from conventional gas reservoir. Langmuir isotherm law and Fick diffusion law are used to established the desorption gas steady diffusion rate expression. Three research works have been done, first, established the production formula of fractured horizontal well based on the model of Genliang Guo rectangle fractured horizontal flow, fracture angle and desorption gas steady diffusion rate are employed to improve the production formula. Second, interact of fractures and desorption are considered, equivalent filtrational resistance is used to establish a capsule model of shale gas steady flow, a new production formula of fractured horizontal well in shale gas reservoir has been derived by the new flow model. At last, rationality of the two formulas has been proved by the calculation of programing based on the field data. Analysised the production influence of formation parameter, horizontal well drilling factors, fracturing effect and desorption gas steady diffusion rate. The production formula of fractured horizontal well in shale gas reservoir and the research of production influence can be used in productivity prediction of later period shale gas reservoir fractured horizontal development. It can also interpret the parameters selection of drilling and hydrofracture more accurately for shale gas reservoir. Optimization design of shale gas reservoir development mode can be improved by the production formula and effect factors research. Desorption gas steady diffusion rate computational method provided us with deeper research about years of stable production, proration, reasonable production system in shale gas reservoir development and how desorption affect production of fractured horizontal shale gas wells.
A New Geomechanical Model Explaining Source Mechanisms of Events Induced by Hydraulic Fracturing in Shale
Authors: Eisner Leo , Stanek Frantisek
Published: June 2014

Optimization of stimulation is key to successful development of unconventional reservoirs. Microseismic monitoring is the most powerful tool to help us understand where and what is happening during and after the stimulation. Yet very little is understood about the relationship between microseismicity and hydraulic fractures: some believe microseismic events are part of the hydraulic fractures, some believe they are resulting from stress changes and fluid leak-off. Microseismic datasets with accurate event locations complemented with source mechanisms lead us to a new level of understanding of the interaction between hydraulic fracturing and seismic response. There are at least four geomechanical models to explain observed failure mechanisms and the opening (or closing) of hydraulic fractures (seismic tensile opening, leak-off cloud of seismicity around the hydraulic fracture, shearing between aseismic tensile opening and horizontal fractures shearing on vertical planes). Unfortunately none of these models is consistent with observations presented in this study. Hence we developed a new geomechanical model of bedding plane slippage and vertical shearing induced by hydraulic fractures in shale reservoirs.

We present a case study including detailed source mechanism inversion for a microseismic dataset from hydraulic fracturing of a shale gas play in the North America. We observe source mechanisms dominated by shear failure with dip-slip and strike-slip sense of motion. The dip-slip mechanisms are prevailingly oriented with shear planes along the maximum horizontal stress. This can be explained as slippage on beddings planes caused by aseismic opening of hydraulic fractures. The strike-slip mechanism show small but real components of non-shear deformation. This can be also explained as slippage on vertical plane perpendicular to maximum horizontal stress with slight opening as these events are direct part of the hydraulic fracture. This model explains large energy difference between seismic and hydraulic energy, and prevailing orientation of the shear planes of the induced microseismic events. In addition, the bedding planes are weak planes in the shale formation likely to fail. The model can better constrain fundamental parameters of induced hydraulic fractures and describe hydraulic fractures and their interaction with the shale plays.
Stakeholder Concerns Against Shale Gas Developments in Europe - The Relevance of Water Management
Authors: Heinz Walter , Hiller Dieter
Published: June 2014

The exploration of shale gas resources in Europe is moving at a slow pace, despite the fact that drilling for reservoir characterization is essential for any further planning. Whether shale gas development in certain regions is economically feasible at all and what such development activities might entail can’t be determined in the absence of critical data. Yet, there is widespread public resistance that influences political decision making and permitting, and that sometimes doesn’t even allow for exploration. Most of the stakeholders concerns are related to perceived environmental risks for water resources as a result of hydraulic fracturing. The main themes are concerns about the contamination of water bodies by fracturing chemicals, methane or flowback water, or concerns about the depletion of groundwater and surface water.

While some of those perceived risks may be overestimated or unsubstantiated, there are real risks that have to be addressed by thorough assessments of the environmental, health and social impacts, and by an integrated approach to water management from sourcing to final disposal. This includes the transportation and distribution logistics for water and wastewater movements. It is essential to establish relevant reference and baseline data on groundwater and surface water systems well ahead of project implementation, to assess risks in a fashion that is understood by interested stakeholders, to define proactive and reactive resource protection measures, and to monitor performance.

This paper suggests an integrated approach to water management that combines the elements of impact assessments, scientific and technical data gathering, and the monitoring of potential impacts across the life cycle of a shale gas project, as well as sourcing, transportation and disposal strategies. All results and measures taken need to be communicated and documented in a clear and transparent manner.
CBM Development Scenario Optimization for Production Sharing Contract, Case Study: Sumbagsel Field, Indonesia
Authors: Ferdian Felik , Ilyas Adrinal , Mediyanti Vina
Published: June 2014

Indonesia according to research by Resource International Inc. Advance. (ARII) along with the Directorate General of Oil and Gas – Ministry of Energy and Mineral Resources has potential resource 453 TCF of CBM which is divided into 11 (eleven) basin on the island of Sumatra, Borneo, Java and Sulawesi. The results of CBM product is expected to be a solution to Indonesia's potential energy shortages in the future relying on energy sources from oil and natural gas.

The utilization of CBM in Indonesia following the fiscal term of Production Sharing Contract (PSC) with a validity period of 30 years. CBM reservoir characteristics are different from conventional gas with smaller permeability, predominantly adsorbed gas and under-saturated conditions require draining the water content (dewatering) before the production period that requires careful planning to produce a viable project either in terms of technical, economic and commercial.

Simulations conducted in Sumbagsel Field in Southern Sumatra, Indonesia, seeking development planning optimization by creating drilling scenarios of CBM wells with a certain amount of accumulation to get a good view of the economic indicators of Net Present Value (NPV), Internal Rate of Return (IRR), Profitability Index (PI) and Payback of Time (POT). The results showed that CBM development can not be done with conventional gas development model approach which uses ‘chuck management system’ to control the production, while the properly management is required in the development of CBM drilling where the number of production wells will be proportional to the increase of production. Knowledge of reservoir characteristics and production optimization management of the number of drilling development wells during fiscal term contract with the production sharing contract will result in the economic development of CBM.
A Physics-Based Method for Production Data Analysis of Tight and Shale Petroleum Reservoirs Using Succession of Pseudo-Steady States
Authors: Shahamat M. S. , Mattar L.. , Aguilera R..
Published: June 2014

Analysis of production data from tight and shale reservoirs requires the use of complex models for which the inputs are rarely known. The same objectives can also be achieved by knowing only the overall (bulk) characteristics of the reservoir, with no need for all the detailed rarely known inputs. In this work, we introduce the concept of continuous succession of pseudo-steady states (SPSS) as a method to perform the analysis of production data. It requires very little input data yet is based on rigorous engineering concepts which works during the transient as well as the boundary dominated flow periods.

This method consists of a combination of three simple and well-known equations: material balance, distance of investigation and boundary dominated flow. It is a form of a capacitance-resistance methodology (CRM) in which the material balance equation over the investigated region represents the capacitance, and the boundary dominated flow equation represents the resistance. The flow regime in the region of investigation (whose areal extent varies with time during transient flow) is assumed to be pseudo-steady state. This region is depleted at a rate controlled by the material balance equation.

The initial flow rate and flowing pressure are used to define the resistance, and the distance of investigation defines the capacitance. The capacitance and resistance are then used in a stepwise procedure to calculate the depletion and the new rates or flowing pressures. The method was tested, for linear flow geometry, against analytical solutions for liquids and numerical simulations for gas reservoirs, exhibiting both transient and boundary dominated flow. Excellent agreement was obtained, thus corroborating the validity of the method developed in this paper.

The proposed method is easy to implement in a spreadsheet application. It indicates that complex systems with complicated mathematical (e.g. Laplace space) solutions can be represented adequately using simple concepts. The approach offers a new insight into production analysis of tight and shale reservoirs, using familiar and easy-to-understand reservoir engineering principles.
An Integrated Approach Towards a Holistic Sedimentological and Pore-Scale Characterisation of Fine-Grained (Shale) Unconventional Reservoirs
Authors: Dasgupta K.. , Kostic B..
Published: June 2014

For a holistic characterisation of fine-grained unconventional reservoirs, our integrated approach utilises coherent, reproducible datasets and refined work practices carried out within a comprehensive quality management system. A typical reservoir characterisation includes integration of sedimentological, structural and pore-scale datasets, however, the specific work flow design depends entirely on the nature of the problem and the availability of appropriate data.

This paper illustrates an example of unconventional reservoir characterisation of a fine-grained formation from the North Sea where the specific aims were to establish the depositional framework for recognising sedimentary environments, recommend sample locations to target specific queries within the sedimentological context for petrographical and geochemical analyses, to investigate what porosity types are present and to assess ‘brittleness’ of the rocks.

First and foremost, high-resolution interpretative graphic core descriptions were carried out at 1:24 scale, utilising Badley Ashton's mudrock-specific lithotypes and depositional packages schemes. Lithotype characterisation uniquely captures very fine-scale attributes (bed to subbed scale), whilst upscaled depositional packages (bed-stack scale) provide a more holistic characterisation from core, as well as from wireline and image logs, where available. Plugs coded by the above descriptors were selected post-logging, for detailed petrographical and geochemical analysis including Rock-Eval pyrolysis within the sedimentological/structural context. Mineralogical data was acquired by whole-rock and clay-fraction XRD analysis, whilst pore-scale fabric/textural investigation were undertaken by conventional light microscopy and BS-SEM. A subset of the plugs was subjected to FIB SEM analysis to characterise any potentially organic matter associated pore system. All these different strands of data were then integrated to evaluate and link the depositional system/sedimentary environment, storage capacity and brittleness of the reservoir in order to assess the overall reservoir potential of the fine-grained formation.
Water Loss versus Soaking Time: Spontaneous Imbibition in Tight Rocks
Authors: Lan Q.. , Ghanbari E.. , Dehghanpour H.. , Hawkes R..
Published: June 2014

The combined application of multi-lateral horizontal drilling and multi-stage hydraulic fracturing has successfully unlocked unconventional tight hydrocarbon reservoirs. However, the field data show that only a fraction of the large water volume used in hydraulic fracturing treatments is recovered during flowback operations. The fate of non-recovered water and its impact on hydrocarbon production are poorly understood.

This paper aims at understanding the relationship between water loss and rock petrophysical properties. It also investigates the correlation between water loss and soaking time (well shut-in time). Extensive spontaneous imbibition experiments are conducted on downhole samples from the shale members of the Horn River basin and from the Montney tight gas formation. These samples are characterized by measuring porosity, mineralogy and TOC. Further, a simple methodology is used to scale up the lab data for predicting water imbibition volume during the shut-in period after hydraulic fracturing operations.
Environmental Stewardship: Lessons for European Unconventional Gas From the United States and Australia
Authors: Wilkinson Paul , von Lany Peter , Lane Alexander
Published: June 2014

Europe is on the cusp of an expansion in the development of unconventional gas resources, and many analysts are turning to the United States (US) and Australia to learn lessons from markets at different stages of the development curve. To date, most attention has been focused on similarities and differences in geology, service industry, and gas price while consideration of environmental stewardship has been dominated by concerns over the potential environmental and health impacts of hydraulic fracturing. Broader issues of local water security, wastewater management, and landscape impact have, in contrast, received less attention.

To address these issues, the authors take an alternative look at the European market by using experiences in the US and Australia to consider the risk-management practices, regulatory measures, and stakeholder-engagement techniques that have achieved greatest success in stimulating the industry while, at the same time, protecting environmental assets. Although the industries in the US and Australia exhibit notable differences to those that may develop in Europe, several overarching observations can be made. The importance of stakeholder collaboration, transparency, and carefully defined boundaries of jurisdiction are some of the key factors identified.

Drawing lessons from these examples and others, the authors conclude by identifying three initiatives essential to the emergence of a viable, publicly acceptable, and sustainable unconventional gas industry in Europe:

Collecting robust and reliable environmental baseline data Using and communicating sound science Implementing collaborative governance

Failure to implement these initiatives could stifle projects, breed uncertainty, promote conflict with existing industries and the public, and potentially discourage investment. Conversely, by implementing the three recommendations, Europe would be in a better position to encourage unconventional gas development in a manner that secures social and economic benefits while maintaining high levels of environmental stewardship.
Shale Gas Boom in the USA Inspires Chinese Operators
Authors: Kang Siwei , Gao Changhong
Published: June 2014

With the depletion of conventional fossil resources and growing demand for energy, unconventional energy is playing a more important role in the world energy market. Nowadays, unconventional gas production contributes to around 50% of total gas output in the USA Shale gas has significantly changed the energy portfolio in the USA and reduced America's dependence on oil and gas imports. The case histories of four major shale gas plays in the USA, Antrim, Barnett, Haynesville, and Marcellus, are discussed in this paper. It is concluded that the phenomenal shale gas success in the USA benefitted from improved horizontal drilling and fracturing technology, positive government policy and tax incentives, and mature surface pipeline system.

China is facing with soaring energy demand and the pressure to cut greenhouse gas emission. These factors have motivated oil operators to explore and exploit the enormous shale gas resources in China, especially in the Sichuan and Tarim Basins. But several factors may hinder the future of shale gas in China. Firstly, Chinese operators have to develop suitable drilling and fracturing technologies. Secondly, lack of water resources may restrain fracturing operations. Thirdly, China lacks mature pipeline system. Fourthly, the Chinese national oil companies may not be interested in producing shale gas due to its low price and low profits. Therefore, it is emergent for the Chinese government to invest in innovations and infrastructure, and allow independent and private companies to engage in the shale gas business.
A Novel Experiment Method of Evaluating the Brittleness of Rock
Authors: Song Lili , Li Yongping , Wang Yonghui
Published: June 2014

The selection of favorable well /layer and the hydraulic fracturing strategy are all based on the rock brittleness in shale gas. Two main methods of evaluation the brittleness of rock have been widely used in field. One is based on the Young's modulus and Poisson's ratio, and the other is based on the brittle mineral component content. But these 2 methods are not good enough in some shale, because the parameter of brittleness is related to the rock failure behavior while the 2 methods can't reveal the failure property. Using the feature points on the complete stress-strain curve is a good option to evaluate the brittleness. But complete stress-strain curve is often hard to be gotten if the stiffness of load frame is not high enough, especially for the shale.

A novel experimental method of rock brittleness evaluation is developed from the nature of rock failure, which is based on the AE (acoustic emission) technology. Because the AE events can reflect the rock failure process, it can characterize the rock brittleness well. More brittle the rock is, more concentrated the AE events occur. That is to say, the concentrated AE events feature shows the rock is brittle, while dispersed AE events feature means the rock is ductile.

Several experiments have been carried with this method on shale and sandstone. The results show that the shale is much more brittle than the sandstone. Meanwhile, the evaluation results are in good agreement with the results from complete stressstrain curve methods and have effectively guided the hydraulic fracturing in field.

This method is easy, accurate, universal and low demand on the load frame. The results can be used to guide the well/layer selection and fracturing design, and to establish the empirical relationship between the rock brittleness and logging data in new region.
Comparison of Empirical and Analytical Methods for Production Forecasting in Unconventional Reservoirs: Lessons from North America
Authors: Dutta Riteja , Meyet Marie , Burns Chris , Van Cauter Frederik
Published: June 2014

The prediction of Estimated Ultimate Recovery (EUR) for a well or group of wells in a development project is critical to accurate reserves estimation. A number of techniques, many of which can be used deterministically or probabilistically, are employed in EUR prediction in mature and maturing unconventional gas and oil plays in North America. These include the use of geological and production data from analogous reservoirs, the use of volumetric methods and recovery factors, analytical models, numerical reservoir simulation and production decline curve analysis (DCA).

Decline curve analysis is arguably the most commonly used method for forecasting reserves in unconventional reservoirs. This paper discusses its basic theory and application, together with the potential pitfalls of using simple empirical production forecasting methods in complex reservoirs. We analyse production data from several US unconventional oil and gas plays and carry out production forecasting using the traditional Arps' methods as a basis for comparison, and newer empirical solutions including the Power Law, Stretched Exponential Decline Model, Duong (and variations thereof). The range of production forecasts provided by these methods is examined, together with methodologies for developing statistically valid type wells in unconventional plays, and how best to determine valid input parameters for the various empirical solutions.

The effect of the variable length of production history available in the various plays, and how it impacts the accuracy of the forecasts is also examined. The results of the analyses are compared with analytical models developed for each play to determine the suitability of each decline curve analysis method: in which plays and under which circumstances they can be applied, and suggest reasonable input parameters and data requirements for each method. Finally, the potential future use of the methods in emerging plays outside of North America is presented.
New Insights From Jurassic Shale Characterization: Strengthen Subsurface Data With Outcrop Analogues
Authors: Zijp Mart , ten Veen Johan , Ventra Dario , Verreussel Roel , van Laerhoven Linde , Boxem Thijs
Published: June 2014

This study shows the first results of an ongoing project on the characterization of variations in lithological and geomechanical properties of targetted gas shale formations. The aim of this study is to get an increased insight into both the fraccability and productivity of a shale formations. Ultimately, this can lead to better localization of shale gas "sweet spots" and prediction of mechanical reservoir behaviour. Since subsurface data is scarce and often widely spaced to achieve this, we did an outcrop study along the Yorkshire (UK) coast on the time and depositional analogue of the Jurassic Posidonia Shale Formation, the Jet Rock Member of the Whitby Mudstone Formation. High resolution (10 cm) sedimentological, geochemical and geobiological sampling, natural fracture analysis and Spectral Gamma Ray measurements are performed.

The mineralogy of the Jet Rock Member is based on geochemical data and thin section point counting and shows more or less equal amounts in Quartz, Kaolinite and Illite with only Pyrite and Calcite changing substantially. Within high TOC layers the percentage of Pyrite increases at the cost of Kaolinite. Fracture analysis of the Jet Rock Member shows a change of fracture density and length on a meter scale and is confined to the bedding. Comparison of the fracture density and mineralogical ratios shows a strong correlation suggesting that identification of the mineralogical signature can be of importance when targeting zones with preferential geomechanical behaviour. Geochemical test show that of the eight meters of black shale studied only one zone of half a meter has a measured TOC value of 15–20%. All other measurements on the other 7.5 meters of the member show an average organic content of 3–5%.

Spectral Gamma Ray (SGR) analysis of the Whitby outcrops shows gradual changes in potassium, thorium and uranium content, while the variation in thorium content is most significant. A direct link between SGR and fracture density is not visible although it is clear that the altering SGR signature is result of the changing minerology and thus possibly linked to the fracture behavior. When comparing the Whitby outcrop results with the SGR results of the Posidonia Formation in the Dutch well Moerkapelle-14 it stands out that the Dutch subsurface values are in general lower than the English outcrop ones. Both thorium and uranium are, for almost the entire formation, lower than the English time-equivalent.
Lower Paleozoic Basins Developed Above the East European Craton in Poland: New Insight from Regional High-Effort Seismic Reflection Data
Authors: Krzywiec Piotr , Malinowski Michal , Lis Pawel , Buffenmyer Vinton , Lewandowski Marek
Published: June 2014

The Lower Paleozoic basin in Poland is located above the southwest edge of the East European Craton, northwest from the Teisseyre – Tornquist Zone which is separating the cratonic plate from the West European Platform (Fig. 1 & 2; Ziegler, 1992; Doornenbal & Stevenson, 2010).

Later Late Paleozoic tectonic movements resulted in compartmentalization of the Lower Paleozoic basin into three sub-basins: Baltic Basin, Podlasie Basin and Lublin Basin (Fig. 3 & 4).

During the Precambrian/Cambrian, the cratonic edge underwent extension and rifting of the Rodinia supercontinent, while Cambrian – Middle Ordovician subsidence was driven by a post-rift lithospheric thermal cooling (Poprawa et al., 1999; Poprawa, 2006a). In the Late Ordovician – Silurian, the cratonic edge was under the strong influence of the Caledonide thrust belt, and was incorporated into its flexural foredeep basin (Poprawa et al., 1999; Nawrocki & Poprawa, 2006). Deposition was dominated by fine-grained organic rich shales, generally derived from the eroded orogenic wedge and deposited in the distal foredeep basin (Poprawa et al., 1999; Poprawa, 2006b). The Silurian Caledonian foredeep basin encompassed vast areas stretching from the present-day Sweden across Estonia, Latvian, Lithuania, Russia (i.e. Kaliningrad District), Poland, Belarus, Ukraine and farther to the southeast (Poprawa et al., 1999; Skompski et al., 2008; Zdanaviciute and Lazauskiene, 2007). Presently available information regarding the Caledonian orogenic wedge is very limited and mostly indirect, based on e.g. provenance studies of the foredeep infill, as it was destroyed and deeply buried during the later tectonic phases (Poprawa, 2006b).
Interpretation of the Silurian Basin of Central and Eastern Europe as a Pro-Foreland Flexural Basin: Implications for Shale Gas Exploration
Authors: Tari Gabor , Poprawa Pawel , Krzywiec Piotr , Popadyuk Igor , Krezsek Csaba
Published: June 2014

The present day collage of various Silurian basin fragments in Central and Eastern Europe (CEE) 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 region, including Poland, Ukraine, Romania and Moldova.

The distal segments of a large Silurian foreland basin associated with the Caledonian collisional orogene, along the perimeter of the East European Craton, can be reasonably followed along strike from NW to SE, from Poland all the way to the Ukrainian Black Sea coast. The foredeep basin sequence onlaps to the NE the various pre-Silurian and crystalline basement units. The Silurian basin of the CEE is interpreted here as a pro-foreland basin, with short-lived (less than 15 m.y.) and extremely rapid (locally more than 1,500 m per m.y.!), accelerating subsidence histories recording a portion of the orogenic history of the broader Caledonian orogeny. Besides the typical subsidence curves and the very prominent onlap of successive Silurian lithostratigraphic units onto the craton, the flexural origin is also supported by the general lack of normal-faulting within the basin, contradicting some interpretations suggesting deposition on the extensional continental margin of the Rheic Ocean. The map-view distribution of the lithofacies within the basin, such as clastic turbidites in the southwestern perimeter of the basin, deepwater shales in the center and neritic carbonates on the northeastern foreland margin, is also consistent with the flexural basin interpretation.
Unconventional Reservoirs: Proper Planning and New Theories Meet the Challenges of Horizontal Cementing
Authors: Pavlock Cole , Bratcher Jason , Leotaud Lennox , Tennison Brad
Published: June 2014

Horizontal wells can present special challenges for cementing operations. Extended-reach lateral sections, unconventional mineralogy, and high-pressure/high-temperature (HP/HT) environments can cause failures during and after the cement job. The high clay content and ductility of these formations force operators to use oil-based mud (OBM) to drill the curve and lateral section. A narrow pore-pressure/fracture-gradient window and tight annular clearance create higher than usual equivalent circulating densities (ECDs) and can affect mud displacement efficiency and cement placement. As unconventional reservoirs become more prevalent, increased focus on the cementing process will be vital to the long-term success of the well. New theories and proper planning will help decrease the probability of an irregular cement job and increase the chances of having zonal isolation for the life of the well.

In this paper, many aspects of the cement job design are discussed and recommendations are provided for horizontal cementing in unconventional reservoirs. New testing methods and additive composition help ensure the compatibility and thermal stability of the cementing fluids while creating more realistic wellbore hydraulic modeling and job optimization. Improved casing attachments and plug sets help increase displacement efficiency, while formation-specific cement designs increase effectiveness of the stimulation method. As multistage sliding-sleeves completion tools become more prevalent and increase efficiency, the cementing operation should align with the overall goal of the completion procedure. With the entire lateral section in one formation, it is not only critical to isolate the target formation from shallower zones but to also create a good annular seal between fracture stages. Without isolation, communication between stages can cause fracture treatments to migrate to unwanted areas. Modeling the expected temperatures, forces on the formation, displacement efficiency, and stress on the set cement sheath allows for a design that meets the expectations during the life cycle of the well. Complex temperature profiles create unfavorable design criteria, so accurate temperature determination is an important element to the cement design. With a renewed focus on the fundamentals of cementing, sufficient planning, and new technology, these unconventional reservoirs can become a manageable and sustainable resource for many years.
Successful Alternating Sequential Hydraulic Multifrac in Two Parallel Horizontal Wells in a Low-Permeability Turbidite Oil Reservoir
Authors: Gutiérrez Guillermo , Perazzo Gerardo , Medina Eber , Sierra Jose , Henriquez Carolina , Salguero Javier
Published: June 2014

A multistage fracturing treatment was performed in two adjacent horizontal wells (Escobal 197 and Escobal 195) in Chicontepec basin. The alternating sequential hydraulic multifrac in two parallel horizontal wells was planned and performed to create a high-density system of low-complexity planar fractures between the horizontal wells, to maximize the contact area with the reservoir and increase the stimulated reservoir volume (SRV). The wells were drilled perpendicularly to the expected fracture azimuth in Pechi-B formation and were completed as openhole using a ball-and-sleeve completion strategy. Thirty-two fracturing stages (16 stages per well) were selected based on an integral analysis of geological, petrophysical, and geomechanical disciplines. This completion technique has been the first stimulation treatment of its kind in Mexico. The fracturing entails adjacent wells in sequence, enabling one well to hold fracture pressure while the adjacent well is being fractured and it also maximizes the exposure of new reservoir rock. The fractures then avoid each other because of the stress pattern set up in the pressured well. The two adjacent horizontal wells were successfully stimulated in 108 hours of continuous work, pumping 95,000 bbl of fracturing fluid and 8.6 million lb of ceramic proppants. The stimulation technique reduced the stimulation cycle time to just four days, and the initial production of the two wells was more than 8,320 B/D, which was more than 10 times the average initial production in the area. The production later stabilized at 2,517 and 1,011 BOPD, respectively. The two horizontal wells produced 240,000 barrels in 90 days of cumulative production, which exceeds 14 times the average of cumulative production from the conventional wells in the field. The application of this completion technology was considered successful, and now it is extending to other fields located in the basin of Chicontepec.
Fractured Reservoir Modeling: Effects of Hydraulic Fracture Geometries in Tight Oil Reservoirs
Authors: Lin M.. , Chen S.. , Chen Z.. , Xu J..
Published: June 2014

Tight oil production is emerging as an important new source of energy supply and has reversed a decline in U.S. crude oil production and Western Canadian light oil production. At present, combination of the multistage hydraulic fracturing and horizontal wells has become a widely used technology in stimulating tight oil reservoirs. However, the ideal planar fractures used in the reservoir simulation are excessively simplified. Effects of some key fracture properties, such as facture geometry distributions and permeability change, are usually not taken into consideration during the simulation. Over simplified fractures in the reservoir model may fail to represent the complex fractures in reality, leading to significant errors in forecasting the reservoir performance. In this paper, we examined the different fracture geometry distributions and further discussed the effects of geometry distribution on well productions. All fracture geometry scenarios are confined by the microseismic mapping data. To make the result more reliable and relevant, a geo-model was first constructed for a tight oil block in Willesden Green oil field, AB, Canada. The simulation model was then generated based on the geo-model and history-matched. A horizontal well was drilled in the simulation model and different fracture geometry scenarios were analyzed. Results indicate that the simulation results of simple planar fractures overestimate the oil rate and lead to relatively higher oil recoveries. In addition, the effect of hydraulic fracture geometries under the higher fracture conductivity is more significant compared to those under lower fracture conductivity.
Automatic Processing of Microseismic Data: Determination of Hypocenter Position and Estimation of Focal Mechanism
Authors: Vicek J.. , Fischer T.. , Vilhelm J..
Published: June 2014

We present an automatic method of processing microseismic monitoring data acquired at the surface with star-like array using the back projection approach that allows simultaneous determination of hypocenter position of events and an estimation of their focal mechanisms. Location coordinates are searched in a grid using two norms for seismogram stacking: STA/LTA for location and stack of real amplitudes corrected by the radiation pattern to estimate the focal mechanisms. From each point of the given grid we compute travel times to all geophones on the surface through the assumed velocity model. Afterwards we do migration of each trace using the computed travel time and stack the STA/LTA ratios of all traces. This process is repeated for each point of the grid. The most probable location corresponds to the maximum of the stack. In the second step a small and fine grid with center in the approximate location is used to refine the hypocenter position. In order to find source mechanisms we use additional grid search in source mechanism angles – strike and dip to find focal mechanism and correct polarity of seismograms according to computed theoretical polarities of the found focal mechanism. We test this method on real dataset of hydraulic fracturing monitoring of a shale gas play. We obtain similar hypocenter positions and focal mechanisms as provided by other methods applied to the same dataset.
Design Optimization of Horizontal Wells with Multiple Hydraulic Fractures in the Bakken Shale
Authors: Saputelli Luigi , Lopez Carlos , Chacon Alejandro , Soliman Mohammed
Published: June 2014

Hydraulic fracturing is currently the completion method of choice in most tight reservoirs; however, the ultimate performance of fractured wells is severely affected by the interfering effects inside the fracture and interfractures. Previous simulation studies investigated the effects of well spacing and fracture length on well productivity in low-permeability oil and gas reservoirs. It was shown that the most important parameters for determining the optimum fracture length are the formation permeability and the stimulated reservoir volume (SRV).

Although a number of studies have examined the performance of horizontal fractured wells and the fracture geometry effect, fracture spacing and intersecting angles in vertical and horizontal wells should be further investigated. This study presents the results of a tight oil reservoir analogy. Reservoir parameters considered include local rock stresses, rock compressibility, absolute and relative permeability, and porosity. The well-completion parameters included fracture length, height, width, conductivity, number and spacing between fractures, fracture intersecting angle, and cased- vs. openhole completion. Fracture modeling considered rigorous description of the hydraulic fracture properties and finite difference reservoir modeling.

Economically attractive reserves recovery was modeled through multiple fracture placements in a 10,000-ft horizontal well. Numerical simulation showed that oil recovery increased between 8 to 15%, while net present value (NPV) increased 8 to 24%, as the number of fractures increased. Based on the critical assumptions in the study (permeability, natural fracture distribution, and stress orientation), an optimum number of fractures was identified. Openhole completions provided better performance in most cases, and recovery was greater for a higher number of contributing perpendicular vs. longitudinal fractures.

The results of the study hopefully can be used to improve the understanding of the role of fracture geometry, spacing, and open/cased-hole completion strategy to enhance an operator's optimum completion design.
Benefits of Novel Preformed Gel Fluid System in Proppant Placement for Unconventional Reservoirs
Authors: Zhou Jia , Sun Hong , Qu Qi , Guerin Michael , Li Leiming
Published: June 2014

Post-treatment production analyses after hydraulic fracturing with crosslinked gel or slickwater often indicate that the treatment did not achieve the designed fractured area, which could be attributed to non-ideal proppant placement in the fracture. Although crosslinked gel provides good proppant suspension, it may not provide the desired proppant transport under downhole conditions. It is also difficult to clean up and thus induces gel damage into the proppant pack and formation. Slickwater treatment reduces gel damage, but proppant settling and banking problems can reduce the chance of achieving optimal fracture conductivity. Several proppant placement techniques have been developed to generate highly conductive paths for hydrocarbons to flow from an unconventional reservoir to the wellbore, such as hybrid fracturing, ultralightweight proppant delivery, and reverse hybrid fracturing.

This paper demonstrates a novel fracturing fluid and its nearly perfect proppant transport characteristics. An engineered method of applying such fluids to optimize proppant placement and maximize fracture conductivity is discussed. The novel fracturing fluids are based on preformed gel fluids. When properly selected, the fluids can ideally suspend proppant under downhole conditions and carry all types of proppants into the fracture. This leads to better transverse and vertical placement of proppant in the fracture and significantly increases the fractured surface area, which is one of most important factors in unconventional reservoir production. The degradability of the fluid can be controlled by reservoir temperature, fluid pH, or breaker loading, which leads to optimized proppant pack conductivity.

This paper discusses the evolution of the technology and laboratory testing results for this unique fluid system. The system has applications in areas requiring high fractured surface area and high regained conductivity, such as unconventional liquids-rich formations.
Is It Possible to Do Unlimited Multi-Stage Fracturing Economically?
Authors: Yuan Feng , Blanton Eric , Palmer Chris , Andersen Clayton , Grogan Alison
Published: June 2014

Over the last decade or so, unconventional shale resources have been playing an increasingly important role in hydrocarbon production due to advanced drilling, fracturing and completion technologies enabling the recovery of previously uneconomic reserves, and multi-stage fracturing technology has been widely used to exploit them in the North American oil & gas industry. During that time the completion process has been evolving, starting with the Plug and Perf method and then with multiple ball seat size actuated sliding sleeves gaining attention. However both methods have their drawbacks, the former requiring multiple re-entries and mill out operations, the latter having a limited number of fracturing stages due to the graduated seat sizes needed and the probability of the need for milling out the seats upon completion to remove flow restrictions (Wozniak 2010).

As a result of these drawbacks, the industry has been driven to the development of some high-performance multi-stage fracturing completion systems which are emerging in the marketplace as alternatives to both plug and perf and traditional ball-activated frac sleeves. Three such unlimited multi-stage fracturing systems, which have been developed in recent years, can be cemented in place if desired and have a full-bore internal diameter (ID) or as close as possible to the host tubular string after fracturing and do not need milling-out operations, reducing overall completion time and improving fracturing and production efficiency. These include: 1)Coiled Tubing (CT)-Operated sleeve – this incorporates a Bottom-Hole Assembly (BHA) which is used to isolate the target zone and shift the sleeve open with fracturing being performed down the CT/Casing annulus on an nearly unlimited number of sleeves.2)An evolutionary ball-activated frac system – this uses a single size ball and ball seat for each zone, which allows an essentially unlimited number of frac stages.3)Radio-Frequency-Identification (RFID) frac sleeves – by simply dropping RFID tags in the completion string, the RFID frac sleeve system can be run with an unlimited number of frac stages.

This paper will review developments in multi-stage fracturing completions, describe in detail their unique features and capabilities which are not available in earlier systems and present simulations of frac efficiency with quantitative comparisons. The analysis will indicate that these three new frac sleeves technologies can be used to optimize hydraulic fracturing operations in both horsepower and stimulated reservoir volume while dramatically reducing overall completion costs.