bluuebunny/crossref_metadata_2025_split huggingface dataset:
Renovation of Old Well Logs Run in Boreholes Drilled with Oil-Base Mud
Authors: Elkewidy Tarek Ibrahim 
Published: May 2016

Abstract
The problem of correcting for oil-base mud filtrate invasion has been resolved using modern well logging technology of tools and interpretation techniques. However, many well logs from old wells remain uncorrected. Old interpretation assumed no oil base mud filtrate invasion. The consequences may vary between unnecessarily perforating a water-bearing zone to even worse by completely by-passing a hydrocarbon formation.
Lau et al. (1989) developed a correction for oil-base mud effects on neutron and density logs, however the standard formation evaluation techniques from the Dual Induction Resistivity Log, DIL, relies on knowledge of the resistivity of the invaded zone, Rxo. Since no electrode-type tool can work in oil base mud to measure Rxo, a synthetically derived Rxo from the Electromagnetic Propagation Time (EPT) or the Thermal Neutron Decay time (TDT) logs is used. In the absence of these unconventional EPT or TDT logs, interpretation is performed assuming no oil mud invasion and the deep induction resistivity, RID, is reading the true formation resistivity, Rt. However, it has been proven that oil mud filtrate will invade the formation sometimes to a diameter greater than 120 inches. This invasion will greatly affect Rt masking the hydrocarbon potential of the reservoir to the extent that a water zone may appear as hydrocarbon-bearing.
Without proper consideration to the oil-base environment surrounding the logging tools, essential petrophysical parameters such as true formation porosity and resistivity cannot be accurately measured. Techniques and concepts such as crossplotting log j versus log Rt or log Rxo, BVW, shale zonation index, fracture partitioning coefficient, etc. may not be all conducted. Evaluation of properties such as Sw, Sxo, Smo, m, n, jma, jf, FII, etc. will not be reliable. Consequently, zonation of a heterogeneous reservoir into its hydraulic units cannot be accomplished.
In this study, a new practical and cost effective technique is introduced to correctly evaluate formations with deep oil-base mud filtrate invasion of old well logs in the absence of EPT, TDT, logs, i.e. without a prior knowledge of Rxo or Rw. This will allow characterization of old reservoirs drilled with oil-base muds using the available old conventional well logs without the need for running new expensive well logs.
Preliminary Analysis of Diagenetic Effects on Basin Scale Overpressure Dynamics
Authors: Scrofani G. , Ruffo P. , Porta G. , Riva M. , Lever V. , Scotti A. , Imperiali I. 
Published: May 2016

Abstract
This study introduces a diagenetic modeling approach which is then applied to a simple one-dimensional scenario with an alternation of sandstone and shale layers. A key focus of the work is the analysis of the role of critical parameters that may drive pressure and overpressure dynamics in a basin. Due to its one-dimensional nature, the modeling technique presented can be currently applied as a Quality Control (QC) tool to assess the occurrence of diagenetic effects that might affect pressure evolution to assist in improving forecasting of overpressures in a new well in the same area or under similar geological settings. Coupling of hydro-geochemical and mechanical processes with the evolution of temperature enables one to model the effect of basin scale temperature-activated reactions on diagenetic scenarios. The resulting set of partial differential equations includes parameters whose values are always affected by high uncertainty. We provide uncertainty quantification (UQ) of the compaction process through a Global Sensitivity Analysis (GSA) of the system response following incomplete knowledge of a set of model parameters. The model response is approximated through a polynomial chaos expansion of the system dynamics. This decomposition provides (a) a GSA based on Sobol indices, and (b) a meta-model of the system that can then be adopted to perform multiple Monte Carlo realizations of the diagenetic process at an affordable computational time. Our results allow to (i) investigate the effect of parametric uncertainty on the system states, and (ii) perform robust parameter calibration within an inverse modeling framework. This work does not disclose significant data from the field or computer work; it contributes to improve our understanding and modeling of diagenesis of sandstones and shales and basin overpressure evolution.
A Modified Archie Relationship - A Novel Approach to Evaluate Carbonate Reservoirs with Regard to Fracture and Isolated Vuggy Porosityfor Sw=1
Authors: Muller-Huber E. , Schon J. 
Published: May 2016

Abstract
Carbonate rocks hosting major proportions of the world's hydrocarbons are characterized by intricate pore systems encompassing different pore scales, shapes and interconnections resulting both from their organic origin as well as different diagenetic processes (e.g. dolomitization, fracturing, leaching, cementation or recrystallization). Apart from interparticle pore space composed of micro-, meso- and macropores, there are also separate and connected vugs (e.g. fractures), influencing important reservoir parameters such as total and effective porosity or permeability. Therefore profound knowledge of the impact of pore types and interconnections on log data has to be acquired in order to ensure accurate evaluation with respect to porosity. Particularly regarding electrical properties and Archie's relationship - having been established for clean rocks and connecting formation resistivity factor F and total porosity - a special modification in carbonates with regard to their complex pore systems is required. Thus a petrophysical database including resistivity and porosity data of a range of carbonate rocks with various pore types (interparticle and vuggy, both separate and connected) needs to be established. The analysis of the database leads to a modified Archie relationship taking account of the effect of separate vugs and fractures on electrical current flow. This novel modification allows a first step towards porosity partitioning in a water-saturated carbonate formation into proportions that are isolated or accessible for electrical current flow and thus also for hydraulic fluid flow - one of the most important features with regard to producibility and recovery. A set of log data from a sample well is presented to apply and test this new approach on carbonates with challenging pore space characteristics. This novel modification of Archie's equation may prove beneficial to fields of research related to reservoir properties in complex carbonate reservoirs.
Identification of Favorable CBM Area Based on a Two-Tier of System
Authors: Feng Lijun , Yuan Zhengrong , Kleverlaan Martijn , Ghosh Sanjoy 
Published: May 2016

Abstract
Coal bed methane is formed during the coalification stages and stored in coal seams, however the preservation of methane within the seams from the time of formation to present day predominantly depends on the evolution of local geological structure and the associated hydrogeological conditions following the coalification stage. Poor trapping conditions are more likely to result in an unfavorable CBM area. In this paper the evolution of geological structure and hydrogeological conditions of the North Shilou (NSL) CBM block is analyzed using an integrated approach. A two-tier system is developed to identify favorable CBM areas: Tier one considers geological structure and hydrogeological conditions; and Tier two the CBM reservoir properties. Two areas with different resource potential have been identified in the NSL block using this approach. One is characterized by higher gas content and saturation and limited groundwater recharge, where lithological trapping is predominant. The other, potentially less favorable, is characterized by lower gas content and saturation along with active groundwater recharge, where hydrodynamic trapping is predominant. The approach is able to explain reasonably the performance of the existing production wells in NSL block to date.
Optimal Fracture Spacing of a Hydraulically Fractured Horizontal Wellbore to Induce Complex Fractures in a Reservoir Under High In-Situ Stress Anisotropy
Authors: Jo Hyunil 
Published: May 2016

Abstract
It has been generally accepted that creating complex fracture networks by hydraulic fracturing is one of the most efficient ways to produce gas from shale gas reservoirs. Although several factors affect development of complex fracture networks, the in-situ stress anisotropy (i.e. maximum in-situ horizontal stress - minimum in-situ horizontal stress) is the most significant factor. Low in-situ stress anisotropy increases the chance of creating complex fracture networks by hydraulic fracturing while high in-situ stress anisotropy reduces the likelihood of complex fracturing.
In order to compensate for high in-situ stress anisotropy without drilling additional wellbores, M.Y. Soliman suggested using a fracturing method referred to as the Texas Two Step Method (TTSM). The method rearranges the sequence of fracturing stages to make use of the induced stress contrast caused by the net fracturing pressure. In this paper, the author has reviewed previously published assumptions with regard to the above method, and has concluded that certain assumptions may not be realistic, e.g., the interaction among propagating fractures were not thoroughly considered.
To analyze the effectiveness of TTSM, this research has developed numerical codes using the Discontinuous Displacement Method (DDM). Through this research, certain critical characteristics related to fracture geometries are shown to be affected through interaction among multiple hydraulic fractures. The effect of these critical characteristics on the TTSM predictions for optimal fracture spacing of multistage fracturing operations is presented.
From the results, it is concluded that curved fractures can increase or reduce the stress contrast induced by the net fracturing pressure, depending on the shape of the curved fractures. This paper further introduces a simple and general formula to calculate the optimal fracture spacing for TTSM.
The Liwan Gas Project: A Case Study of South China Sea Deepwater Drilling Campaign
Authors: Triolo David , Mosness Tracy , Habib Rana Khalid 
Published: May 2016

Abstract
In September 2006, Husky Energy discovered the Liwan gas reservoir in its South China Sea Block 29/26. A 6th generation, deep water semi-submersible was contracted and subsequently drilled 26 deep water wells (700 - 1600 m water depth) consisting of 10 exploration, 10 appraisal and 6 development wells, tested 6 wells between November 2008 and November 2011. The exploration program discovered several additional sandstone, gas-bearing reservoirs two of which will also be commercialized. During the 1,011 days of drilling and testing activity, the rig and supporting onshore teams did not incur a lost time accident. The rig team drilled 61,593 m of hole below the mudline and ran the associated strings of casing. Non-productive time consumed 265 days (26.2%) consisting of 65 days waiting on weather, 147 days of rig repair, and 53 days of other unscheduled events.
Laboratory Study and Field Application of Fiber-Based Fracture Reorientation Technology
Authors: Yang Shi , Fujian Zhou , Xianyou Yang , Xiongfei Liu , Shengjiang Lian , Xiangdong Li 
Published: May 2016

Abstract
When implement fracture treatment in fractured reservoir or wells had been fractured before, new fractures need to be formed in a beneficial position so that the reservoir can be connected with wellbore effectively. In fiber-based fracture reorientation technology, degradable fiber is utilized as diversion agent to block up original fractures, and divert the fluid to open new fractures. To validate this reorientation effect, this paper designs the physical simulation experiment with big size samples (300mm×300mm×300mm), and real tri-axial stress simulation system. This system can apply stress on the rock from 3 different directions during the fracturing physical simulation experiment.
The results indicate that: multi-fracture system formed in every rock sample simulated with fiber-based fracture reorientation technology when different tri-axial stress applied on the samples. Fiber-based fluid can block up the original fractures effectively and open new fractures in different directions. That is to say, this technology can improve SRV (stimulated reservoir volume) significantly.
Field test and fracture monitoring with tracer had been conducted. The tracer signature shows that multiple fractures have been created after treated by fiber-based fracture reorientation technology.
Fiber-based fracture reorientation technology is an effective treatment to create multiple fractures, and it is a prominent stimulation method for the fractured reservoir and the wells need to be re-fractured.
Silurian Source Rock System in Time and Space
Authors: Spaak Pieter 
Published: May 2016

Abstract
With the rising interest in unconventional oil and gas plays, the need for better understanding and detailed reconstructions of source rock systems becomes even more important than for conventional plays. One of the Series in which these occur in large numbers is the Lower Silurian. In this presentation, the variation in (depositional) setting for the Silurian source rocks will be illustrated, through a careful reconstruction of the Silurian flood in time and space. Although these source beds typically occur at or near the base of Silurian, some are clearly linked with oceanic upwelling, some accumulated in relatively confined foreland basin settings whereas others were formed on a broad but tectonically and glacially modified Gondwana shelf. This contribution illustrates that the depositional, temporal and 'tectonic' variations for one of the 'so-called' global source rocks events can be considerable. Generalizations and un-calibrated use of models, analogues and properties should not be made.
AVO Research on Coalbed Methane Reservoirs in East Ordos Basin
Authors: Zhang Tieqiang , Sun Pengyuan , Qian Zhongping , Ma Guangkai 
Published: May 2016

Abstract

DESCRIPTION:
In east Ordos basin, there are plenty of coalbed methane (CBM) resources. However, the coalbeds are of strong heterogeneity due to laterally variant thickness and gas contents. Consequently, the heterogeneity gives rise to the great challenges for fine reservoir prediction and evaluation in seismic exploration. For the purpose of applying AVO to CBM prediction, in this paper, combining with geological and geophysical characteristics of CBM reservoirs NO. 5 coal seams from drilling, logging and the relationship between elastic parameters and gas contents in the lab, we established a set of thin coalbed models with different thickness and gas contents to model AVO using reflectivity method. Subsequently, AVO responses to gas contents and thickness of CBM reservoir are systematically investigated.

APPLICATIONS:
Our researches are theoretical discussion about the relationships between AVO responses and coalbed thickness and gas contents. These relationships can be applied to exploration of CBM reservoirs in practice.
Athabasca Oil Sands: Application of Integrated Technology in the Identification of Commercial Thermal and Mining Opportunities
Authors: Moreton David , Carter Joan , Peacock Mike , Rogala Becky 
Published: May 2016

Abstract
The heavy oil deposits of Canada contain an estimated 1.8trillion barrels of bitumen in place. The Early Cretaceous McMurray Formation in the Athabasca region of northern Alberta contains about 960 billion barrels of bitumen in place and can be developed through surface mining and thermal in situ techniques. This paper examines the key subsurface development challenges associated with commercializing oil sands developments and demonstrates how knowledge of regional reservoir distribution and the use of an integrated technology approach are vital in the identification, selection, and ranking of the highest quality resource opportunities at the exploration scale. The regional geology of the Western Canada Basin and the Athabasca area will be reviewed.
At the development stage the conventional approach to evaluate Athabasca oil sands properties requires closely spaced coreholes drilled 100 m to 400 m apart. This approach is being applied to understand reservoir presence and continuity, lithofacies distribution, net-to-gross and bitumen saturation. Fluvial estuarine point bar reservoirs form a large portion of the resource that is amenable to development. Point bar scale, stacking style and preservation potential varies considerably throughout the McMurray resource. Examples will be shown from 3D seismic and corehole data to demonstrate spatial changes in stratigraphic complexity within the McMurray Formation. The importance of detailed reservoir characterization studies and the impact on thermal in situ and mining recovery mechanisms will also be discussed.
This paper will demonstrate that an integrated core, well log, and high resolution 2D and 3D seismic strategy with the appropriate sequencing can avoid unnecessary data acquisition and financial pre-investment through removal of non-optimal corehole placement and corehole reduction. This approach allows identification and selective targeting of the highest quality and lowest complexity project-scale resource first with the lowest development uncertainty and greatest economic chance of success.
Geomechanical Characterisation and Modelling Help to Unlock Shale Gas Reservoirs in the Southern Sichuan Basin
Authors: Yuan Roger , Dwan Fa , Singh Navpreet , Jin Liang , Soo Danny , Wang S. , Li X. , Lin M. 
Published: May 2016

Introduction
Shale gas reservoirs in compressional tectonic settings are commonly composed of shale matrix with uneconomically low porosity, permeability, and potentially high retention risk. To effectively and economically recover hydrocarbon from such tight reservoirs, it is important to optimize well placement and hydraulic fracture stimulation in order to maximize the stimulated rock volume (SRV). To achieve this, the application of geomechanics plays a critical role in determining subsurface stress field, identifying brittle and fraccable shale intervals and predicting natural fracture network in a structurally complex setting.
The lower Silurian Longmaxi shale distributed in the Southern Sichuan basin is characterized by a lower section of graptolite-bearing black to dark-grey, calcareous-siliceous shale, generally several metres thick, overlain by an upper section of grey calcareous shales/mudstones and siltstones, interbedded with an increasing number of thin limestone layers towards the top of the formation. The averaged total porosity of the shale package is generally low, and the averaged permeability is typical of other shale gas plays in the basin. Subdivision of shale reservoirs is based on the presence of markers, log motifs and petrophysical characteristics, and is broadly divided into Zone 4 to Zone 1 in descending order. There is a general decrease in silica components from Zone 1 to Zones 4. The link between high quartz and TOC content with favorable porosity and permeability makes Zone 1 the best reservoir quality in Longmaxi shale within the intervals of interest.
To produce from such ultra-low matrix permeability shale formations, hydraulic fracture stimulation is demanded to increase in-situ permeability and to enhance accessibility to reservoir hydrocarbons. In this sense, geomechanics becomes an important element as it assists in assessing shale fraccability which includes subsurface stress states, mechanical properties, rock fabrics and expected stimulation patterns.
The purpose of this paper is to give an overview of the preliminary evaluation of stress setting, geomechanical properties, stimulation potential and related technical challenges of the Longmaxi shale play in the Southern Sichuan basin. By means of reservoir characterization and modeling undertaken at different scales, geomechanics provides an opportunity to unlock the shale play towards commercial development.
Hydrocarbon Risk and Uncertainty: Indian Scenario
Authors: Dani K.C. , Baskaran V.K. , Gupta D.K. , Urkude A.M. 
Published: May 2016

Abstract
Hydrocarbons exploration and bidding is a high risk venture in every project that is taken by any corporation. There is always a chance of failure with the total investment made versus chance of success. If the calculated pay back amount less than the expenditure, then a company may reject the project or take less than 100% working interest in operation to tolerate risk. Low total resource volume, minor prospects, very low probability of success (POS) and low or very low level of knowledge (LOK) are some of the characteristics study play major role.
Royal Dutch shell won the license for the Mangala block RJ-ON-90-1 of Rajasthan (India) in the year 1992 from Indian Government with a production sharing contract (PSC). In 1998, Royal Dutch shell sunk a well in area and used logging probe (to detect the hydrocarbons) which gave negative reading, Cairn had 10% of stake in the leasehold at that time. It then purchased the complete leasehold from shell in 2002 and now producing from one of the highest oil reserve region in India. Shell lost the golden opportunity of huge production because of a wrong reserve estimate.
Another case describes the world's biggest natural gas reserve discovery of D-6 block in Krishna Godavari basin in Southern India during 2002 by Reliance Industries. The proved and the probable reserves were estimated to be 9.65 TCF initially and many projects were developed based on gas generation from D-6. As of now, the production declined to 1.93 TCF with a decline of 80% calculated. Within a decade, the production declined and the future projected power projects of India suffered because of the declined gas supply.
An assessment of reservoir performance, geological models, geophysical and geochemical information and the basin modelling capabilities is used to estimate likely volumes of hydrocarbons in place at particular sites.
Improving Mud Removal and Simplifying Challenging Cement Design: A Deepwater Case History in the South China Sea
Authors: Brandl A. , Acorda E. , Ellis T. , Bray W. 
Published: May 2016

Abstract
The study presents an innovative cement spacer fluid based on microemulsion technology and an operationally simple cement design using a water-based multifunctional polymer. A case history is described where their combination was successfully applied on a deepwater exploration well in the South China Sea. Laboratory testing, modeling, and engineering design that preceded the field operation are outlined. The spacer's performance to clean the mud from contact surfaces was verified with the goniometer method. Mud/spacer and spacer/cement tests for optimum compatibility were conducted and a fluid friction pressure chart for the mud-spacer-cement train at different displacement rates was generated. The results show that the designed spacer is highly effective in displacing the mud and converting an oil-wet surface to a water-wet surface, and therefore to provide a clean and water-wet surface to which cement can strongly bond. A water-based multifunctional polymer in the designed cement slurry was tested to validate its ability to adjust slurry properties for deepwater challenges. The cement slurry was easy to mix at surface, stable under downhole conditions, and had a sufficient short transition time at low temperature, preventing water and gas intrusion. Furthermore the evaluated multifunctional polymer was found to work as a stabilizer and extender as well as provide very good fluid loss, free fluid, and gas control. As a consequence, the multifunctional polymer reduces the total number and amount of required chemicals, thereby simplifying logistics and operations for deepwater wells. The presented spacer and cementing technologies contribute to successful zonal isolation of deepwater wells and so minimize risks as well as expensive rig and nonproductive times due to remedial work.