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Agrawal A.,Chevron | Wei Y.,C and C Reservoirs Inc. | Cheng K.,Texas A&M University | Holditch S.A.,Texas A&M University
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2010

With the increased demand for energy and the declining conventional hydrocarbons worldwide, energy companies are turning to unconventional resources, such as shale gas. With over 2,000 TCF gas in place indentified in just 5 shale gas plays in the United States, shale gas formations are now the number one targets for exploration drilling. Furthermore, there are still many more major shale gas plays and basins waiting to be explored, evaluated and developed. Because of the extremely low permeability of most shale formations, it is essential to select the appropriate completion techniques for shale gas reservoirs. There are very few papers in the petroleum literature that provide a logical method to select completion techniques for given shale gas reservoir conditions. There are papers discussing successful completion techniques that seem to work for a specific shale. We have used many of these SPE papers to help define "best-practices" in completing shale gas reservoirs. We then developed logic to determine the best practice on completing shale gas reservoirs as a function of reservoir conditions. In this paper, we will specifically cover the logic we have developed for choosing completion techniques on shale gas reservoirs. First, we performed a literature review on the five basins as well as on all shale gas plays in the U.S. to determine the best practices in shale gas completion techniques in fluctuating price environments and identify key geologic parameters that affect overall well performance. From our literature review, we identified seven pertinent geologic parameters that influence shale gas completion practices. Next, we identified different completion trends in the industry far different geologic settings. Subsequently, we generated an economic model and performed sensitivity analysis to determine optimal completions for each gas shale basin. Based on these economic models, we developed the decision flowcharts to select completion techniques. Finally, we programmed the flowchart and we call this program as Shale Gas Advisor. This program can be used to determine optimum completion best practices for not only the five gas shale basins discussed, but also, for gas shale plays that have similar geologic attributes. We validated the program with published case histories in the SPE literature. Copyright 2010, Society of Petroleum Engineers.


Lu X.,C and C Reservoirs Inc. | Sun S.,C and C Reservoirs Inc. | Dodds R.,C and C Reservoirs Inc.
SPE - DOE Improved Oil Recovery Symposium Proceedings | Year: 2016

This paper presents the basic reservoir characteristics and the key improved oil recovery/enhanced oil recovery (IOR/EOR) methods for sandstone reservoir fields that have achieved recovery factors toward 70%. The study is based on a global analog knowledge base and associated analytical tools. The knowledge base contains both static (STOIIP, primary and ultimate recovery factors, reservoir/fluid properties, well spacing, drive mechanism, and IOR/EOR methods etc.) and dynamic data (oil rate, water-cut, and GOR, etc.) for more than 730 sandstone oil reservoirs. These reservoirs were subdivided into two groups: heavy and conventional oil reservoirs. This study focuses on the reservoirs with recovery factors great than 50% for heavy oil, and recovery factors from 60% to 79% for conventional oil with a view to understand the key factors for such a high recovery efficiency. These key factors include reservoir and fluid properties, wettability, development strategies and the IOR/EOR methods. The high ultimate recovery factors for heavy oil reservoirs are attributed to excellent reservoir properties, horizontal well application, high efficiency of cyclic steam stimulating (CSS) and steam flood, and very tight well spacing (P50 value of 4 acres, as close as 0.25 acres) development strategy. The 51 high recovery conventional clastic reservoirs are characterized by favorable reservoir and fluid properties, water-wet or mixed-wet wettability, high net to gross ratio, and strong natural aquifer drive mechanism. Infill drilling and water flood led to an incremental recovery of 20% to 50%. EOR technologies, such as CO2 miscible and polymer flood, led to an incremental recovery of 8% to 15%. Homogeneous sandstone reservoirs with a good lateral correlation can reach 79% final recovery through water flood and adoption of close well spacing. The lessons learned and best practices from the global analog reservoir knowledge base can be used to identify opportunities for reserve growth of mature fields. With favorable reservoir conditions, it is feasible to move final recovery factor toward 70% through integrating good reservoir management practices with the appropriate IOR/EOR technology. Copyright 2016, Society of Petroleum Engineers.


Lu X.,C and C Reservoirs Inc. | Sun S.,C and C Reservoirs Inc. | Jenkins D.,C and C Reservoirs Inc.
Society of Petroleum Engineers - Abu Dhabi International Petroleum Exhibition and Conference, ADIPEC 2015 | Year: 2015

Limited data is available for a new discovery at the preparatory stage for the plan of development (POD). Uncertainties exist such as the depositional environment of the reservoir and individual sandbody type, reservoir heterogeneities and fluid properties. This paper presents an innovative and unique method for the qualitative and quantitative evaluation of the influences of these uncertainties on production performance and final recovery factor. The developed methodology enables reservoir engineers and development geologists to conduct uncertainty assessment on production performance and final recovery factors by using a global analogs database and proprietary analytical software tools, including performance forecasting, characterization and attribute cross plotting, etc. The process consists of four steps: (a) selection of the analog reservoirs, (b) performance forecast, (c) uncertainties evaluation, and (d) analysis of key drivers impacting performance and recovery factor. In our case study, Field A is in its POD study stage. Based on available information, reservoir sand in Field A potentially consists of sandbodies of either fluvial channel (FC), distributary channel (DC) or combined fluvial and distributary channels (CFDC). Uncertainty evaluation results indicate that the sandbody of FC, DC and CFDC will produce ultimate recovery factors of 35.9%, 37.9% and 39.7% respectively for the medium-case scenario and 52.4%, 54.3% and 59.2%, respectively for the high-case. The various sandbody types also have a great influence on performances of life-cycle production profile, peak production rate and water-cut variations. Analog analysis of the same sandbody type reveals the impact of three group specific attributes on the ultimate recovery. Compared with the normal approach of conventional geological modeling and reservoir simulation, the analog solution using the proprietary software tool is an efficient process and provides reasonable results. Copyright 2015, Society of Petroleum Engineers.


Jenkins D.,C and C Reservoirs Inc.
Hart's E and P | Year: 2010

Successful exploration in the oil and gas exploration industry is based on detailed exploration play fairway analysis and accurate prospect definition. Subsurface geological analogs should form an integral part of the exploration and workflow process to help reduce exploration risk. Analogs are powerful tools in helping to define exploration plays and in benchmarking exploration prospects. Key elements of plays can be transferred within and between basins, while individual plays and prospects never are exactly identical. IC&C Reservoirs' field analog product is one such tool that has expanded from its early stage as a compendium of field data into a dynamic global analog system, known as the digital analogs knowledge system (DAKS) that captures and analyzes data and information on more than a thousand of the world's most important reservoirs and fields.


Meng Y.,Northeast Petroleum University | Zhu H.,Northeast Petroleum University | Li X.,Petrochina | Wu C.,C and C Reservoirs Inc. | And 4 more authors.
Shiyou Kantan Yu Kaifa/Petroleum Exploration and Development | Year: 2014

The vertical distribution and geological origin of secondary porosity zones have been studied in the tight tuffaceous dolomites of the second member of Permian Lucaogou Formation, Santanghu Basin, Xinjiang, China, and the lateral distribution of secondary porosity zones is predicted using the thermodynamic method. There are three secondary porosity zones in Malang-Tiaohu Sag, formed by reservoir dissolution by the acids including the organic acids generated from decarboxylation of kerogen and the inorganic acids generated from the clay mineral transformations. Gibbs free energy increments of dissolution reactions for different minerals are calculated under various pressures and temperatures to investigate the lateral distribution of secondary porosity zones, combined with litho-facies distribution of the second member of the Lucaogou Formation. Calculation result shows deeply buried dolomite strata are most prone to be dissolved and secondary pores in the second member of the Lucaogou Formation have been formed by tuffaceous dolomites. In general, the most developed secondary porosity zones with favorable tight oil reservoir potentials are located in the central Malang-Tiaohu Sag, overlapped with the high-quality source rocks that are semi-deep to deep lacustrine facies in origin. ©, 2014, Science Press. All right reserved.


Meng Y.,Northeast Petroleum University | Zhu H.,Northeast Petroleum University | Li X.,Petrochina | Wu C.,C and C Reservoirs Inc. | And 4 more authors.
Petroleum Exploration and Development | Year: 2014

The vertical distribution and geological origin of the zones of secondary porosity have been studied in the tight tuffaceous dolomites of the second member of Permian Lucaogou Formation, Santanghu Basin, Xinjiang, China. The lateral distribution of secondary porosity zones is predicted using the thermodynamic method. Three secondary porosity zones were identified in Malang-Tiaohu Sag. The secondary porosities were formed through reservoir dissolution by acids, which include organic acids generated from decarboxylation of kerogen and inorganic acids generated from the clay mineral transformations. Gibbs free energy increments of dissolution reactions for different minerals are calculated under various pressures and temperatures to investigate the lateral distribution of secondary porosity zones, with respect to the litho-facies distribution of the second member of the Lucaogou Formation. Calculation result shows that 1) deeply buried dolomite strata are most prone to be dissolved and 2) secondary pores were mainly formed in tuffaceous dolomites. In general, the most developed zones of secondary porosity with favorable tight oil reservoir potentials are located in the central Malang-Tiaohu Sag and over the high-quality source rocks that are semi-deep to deep lacustrine facies in origin. © 2014 Research Institute of Petroleum Exploration & Development, PetroChina.


Meng Y.,Northeast Petroleum University | Hu Y.,Northeast Petroleum University | Li X.,Petrochina | Hu A.,Northeast Petroleum University | And 4 more authors.
Oil and Gas Geology | Year: 2014

Commercial oil flows were tested in the tight vitric and crystal sedimentary tuff reservoirs of the 2nd Member of Tiaohu Formation(P2t2)in Malang-Tiaohu Sag, Santanghu Basin. In order to reveal the distribution pattern of tight oil, we studied the influences of lithofacies and diagenesis on physical properties of volcanic reservoirs. And plane distribution of four types tight reservoir of P2t2 were predicted through numerical modeling of diagenesis and in combination with lithofacies map. The results show that the quality volcanic reservoir decreases with increasing levels of diagenesis; Pyroclastic rock and tuff are optimal reservoirs, followed by vitric and crystal sedimentary tuffs and pyroclastic rocks, and lavas show the worst reservoir property. The conventional reservoirs(porosity≥9%) distribute in the southern Malang-Tiaohu Sag, and slight tight reservoirs(7%≤porosity<9%) and strong tight reservoirs(4%≤porosity<7%) are located in the central-northern of Malang-Tiaohu Sag. Effective traps are the main exploration targets in area with conventional reservoirs, while the reservoirs and hydrocarbon source should be the focuses of study in area with tight reservoirs.


Wu C.,C and C Reservoirs Inc. | Bhattacharya J.P.,McMaster University | Ullah M.S.,University of Houston
Journal of Sedimentary Research | Year: 2015

Most outcrops of fluvial deposits consist of a series of cliff exposures, either natural or manmade (e.g., roadcuts). Predictions, and especially observation of plan-form geometry, such as might be made with numerical experiments or from studies of modern rivers, are challenging to test in most ancient outcrops. This study examines ancient exhumed channel belts from the Cretaceous Notom Delta of the Ferron Sandstone Member in south-central Utah. Extensive plan-view exposures with local vertical cliff exposures allowed documentation of channel plan-form, channel-belt dimension, bar migration patterns (translation versus expansion), and cross-sectional facies architecture. Channel-fill thickness and bedding structure, documented from the cliff exposures, were used in paleohydraulic reconstructions. Approximately 270 paleocurrent directions were integrated with grain-size measurements to reconstruct the 3D facies architecture. Paleocurrent measurements are consistent within specific facies architectural units (such as unit bars) and show systematic variation at the channel-belt scale that can be used to infer channel and bar migration patterns. In this example, the migration pattern of the single-thread channel bend was interpreted to change from expansion to translation with a corresponding bend sinuosity that increased from 1.01 to 1.44. Inclined large-scale foresets are interpreted to be indicative of unit bars. Empirical equations result in estimated average channel depths from 1.7 m to 3.6 m with corresponding widths of 23 m to 89 m respectively. These empirical estimates match the dimensions measured in the field. For example, channel widths of around 50 m were measured from abandoned channel fills. Bar thickness, measured from vertical outcrops, ranges from 5.4 m to 6.3 m, which yields a narrower estimate of channel width ranging from 47 to 59 m. Integration of sediment size, bedforms type, and channel depth were used to estimate the discharge of the river, which is on the order of < 400 m3/s. This suggests that the Ferron deltas were characterized by small, steep-gradient "dirty" rivers, which is consistent with the hyperpycnal nature of linked downstream deltaic systems. Copyright © 2015, SEPM (Society for Sedimentary Geology).


Zhang T.,University of Texas at Austin | Yang R.,University of Texas at Austin | Yang R.,C and C Reservoirs Inc. | Milliken K.L.,University of Texas at Austin | And 3 more authors.
Organic Geochemistry | Year: 2014

We report on the composition of mudrock gases released under vacuum by ball-mill rock crushing and pressure induced fracturing. Nine core samples from organic rich Barnett Shale were used in this study. TOC content varies from 3.3-7.9%; thermal maturity varies from 0.58-2.07%Ro.Our results show that both thermal maturity and gas desorption contributes to changes in the CH4/CO2 ratio of gases released during rock crushing. CH4/CO2 ratios of these gases are lower at low thermal maturities and higher at high thermal maturities because more CH4 rich gas is generated at higher maturity levels. CH4/CO2 ratios decrease with longer rock crushing times because of the increase in the CO2 rich gas contribution. However, no obvious compositional fractionation occurs among C1, C2 and C3 of crushed-rock gas and C1/C2 and C2/C3 ratios remain nearly constant during crushing although these ratios are greatly increased overall when the level of thermal maturity is high. Gas geochemical parameters (C1/C2, C2/C3, and i-C4/n-C4) of released gas are good indicators of thermal maturation of organic rich shales. The CH4/CO2 ratio is a function of selectivity, partition coefficients and (possibly but less likely) sorption kinetics between CH4 and CO2 molecules in shales. Trends in released gas yield and gas chemistry during rock crushing relate to gas storage states and pore connectivity. The δ13C1, δ13C2 and δ13C3 values of gas released from particles of coarser size (> 250μm) are similar to values of gas produced from Barnett shales after hydraulic fracturing. CH4 dominated gas appears to be stored in larger connected pores and is therefore released during the initial stages of crushing. The carbon isotope values of methane, ethane and propane are heavier in the more thermally mature samples, suggesting that this released gas is representative of the gas chemistry of subsurface rocks. Retrieval of gas chemistry data from existing core samples provides information of great relevance for understanding deep shale gas reservoirs. © 2014 Elsevier Ltd.


Lu X.G.,C and C Reservoirs Inc. | Sun S.Q.,C and C Reservoirs Inc. | Xu J.,C and C Reservoirs Inc.
Society of Petroleum Engineers - International Oil and Gas Conference and Exhibition in China 2010, IOGCEC | Year: 2010

More than 120 clastic reservoirs were examined to extract knowledge of application of thermal recovery and waterflood to heavy or extra-heavy oil (less than or equal to 25 °API gravity). The thermal recovery methods discussed include cyclic steam injection, steam flood, in-situ combustion, hot water injection and SAGD. Key parameters of reservoir and fluid properties and production engineering are summarized in detail for reservoirs where one or more of the above EOR methods or waterflood are applied. These include: (1) reservoir characteristics such as sandbody facies type, permeability, porosity, oil saturation, reservoir depth, net pay thickness and net to gross ratio; (2) crude oil properties including API gravity, viscosity, GOR, and FVF; (3) well spacing and ultimate recovery factor; and (4) controls on incremental recovery and ultimate recovery factor. Controls on ultimate recovery factor for each of the above methods were analyzed. It was found that the basic controls are API gravity, viscosity, reservoir depth, net to gross ratio and well spacing. Thermal recovery methods are mainly applied to reservoirs less than 1100 m deep with crude oil API gravity less than 20°, and typical well spacing of 2-5 ac. The ultimate recovery factor is variable, ranging from 9% to 79%. The most commonly applied thermal recovery methods are cyclic steam injection and steam flood. In-situ combustion has also been successfully applied to some reservoirs with ultimate recovery up to 45%. SAGD technique applied to extra-heavy oil reservoirs is able to improve recovery by 45% to 50% of STOIIP. Waterflood, which has been widely applied to relatively "light" heavy oil with API gravity greater than 15°, can yield good recovery provided that well spacing is close and throughout injection is sufficient. The secondary recovery method is usually implemented in reservoirs at depths greater than 600 m with well spacing of 6-50 ac. Typical ultimate recovery factors for reservoirs with waterflood ranges from 20% to 45%. Copyright 2010, Society of Petroleum Engineers.

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