bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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.
Accurate Reservoir Evaluation in Exploration Gas Wells: A Case Study in Malaysia Basin
Authors: Hassan Rozlin , Malaysia Lundin , Haddad Sammy , Wa Wee Wei , Johan Zailily , Lim Lee Chin
Published: May 2016

Reservoir fluid composition and reservoir parameters characterization are fundamental for the accurate reservoir description during exploration phase and successful reservoir management in gas field development planning. Key reservoir fluid parameters namely hydrocarbon composition and Carbon Dioxide (CO2) are essential input to comprehensive production and reservoir engineering studies.

The paper presents the exploration work done through three gas wells campaign in two main Malaysia basins. The formation is mainly thinly laminated sand-shale beds and the main objective for the operator is to acquire an early and quick identification of hydrocarbon prospect for appraisal wells planning. With that, compared to conventional PVT lab analysis which can easily take weeks to months to complete and full scale DST that offers higher operational complexity and cost, downhole fluid analysis was deployed.

Downhole fluid analysis has successfully identified the reservoir fluid composition and properties for different fluid types. In this offshore Malaysia basin, high CO2 content was not expected geologically, high CO2 was measured in several sands of interest and this early identification on non-hydrocarbon prospect avoids unnecessary cost, time and operational risks. This work presents the successful downhole reservoir fluid identification in mobility range of 23.2 to as high as 5263.8 md/cP. The methodology, applications and suggested best practices applied throughout the campaign are presented in this paper.
Quality Assurance of Carbonate Rock Special Core Analysis - Lesson Learnt from a Multi-Year Research Project
Authors: Ma S. Mark , Belowi Ali , Pairoys Fabrice , Zoukani Ahmad
Published: May 2016

Core data has historically been used as the ground truth in many upstream applications, such as formation evaluation, geological modeling, and reservoir simulation. The importance bestowed upon the data requires that core analysis programs are properly designed and the data is thoroughly quality controlled. Otherwise, a high percentage of the data, especially from special core analysis (SCAL), may not be usable. To design a fit-for-purpose program and produce quality results, potential issues related to the analysis of the targeted reservoir rock and fluids need to be fully understood and taken into account. Many lessons have been learnt from a multi-year project studying drainage and imbibition electrical properties in carbonate rocks, chief among them are related to rock cleaning, porous plate preparation, and test equilibrium conditions.

Results generated in this study show that conventional cleaning may be sufficient for a porosity measurement provided that rock is not extremely heterogeneous. Specially designed cleaning procedures and solvents should be applied for wettability restoration as demonstrated from various wettability measurements. In using porous plate for resistivity index (RI) tests, the main challenges are to prepare the porous discs to oil-wet and flow crude oil through them. Special procedures have been developed to address these challenges successfully. In performing equilibrium RI tests, data shows that a test cycle may last for many months, or even years, and often may be terminated prematurely due to equipment/ sample failures. This issue can only be resolved by adopting a non-equilibrium method with in-situ saturation monitoring and/or numerical simulation algorithms.

Findings from this study can help others to better understand some of the key issues in dealing with carbonate rocks in the core analysis laboratory, thus design a proper SCAL program to produce quality SCAL data.
An Integrated Approach to Evaluate the Further Development of the Changbei Unconventional Tight Gas Reservoirs
Authors: Du Kuifu , Schaeftlein Susanne , Mahiya Glenn , Thum Matthias , Marden Roy , Mohamed Taha , Yang Yatao , Hong Hong
Published: May 2016

Shell and PetroChina have been successfully developing the Main Changbei P1S2 QA Reservoir using the advanced technology of openhole dual lateral horizontal wells since 2005. The scope of this project has been expanded to further develop the Changbei Main Reservoir and also to appraise and develop the Unconventional tight gas Reservoirs. The Unconventional tight gas Reservoirs have not been commercially developed to date and are geologically very different from the Main Reservoir. The team employed front end loading and decision based modelling to manage the complexities of essentially developing a green field within a brown field, and unconventional microDarcy reservoirs above and below a more conventional milliDarcy reservoir. The field was divided into type areas based on reservoir quality and development maturity. The Main Reservoir modelling approach is conventional but the Unconventional Reservoirs will require single-well multi-reservoir box models to facilitate probabilistic uncertainty work flows and type curve generation. Synergies between the Main and the Unconventional Reservoirs have also been considered.
World First: Drilling with Casing and Riserless Mud Recovery
Authors: Peyton J. , McPhee A. , Eikemo B. , Evans H. , Utama B.
Published: May 2016

This paper discusses the planning and operational aspects of drilling with casing (DWC) combined with riserless mud recovery (RMR), along with the benefits experienced compared to conventional drilling. The process of identifying and mitigating risk when applying new technologies to ensure a first time success will also be discussed.

The Dampier Sub-Basin offshore Australia presents major challenges to tophole operations when drilling through the problematic 'Bare Sands.' The formation is composed of highly porous sand in which lost circulation is often encountered. Severe losses prevent sufficient hole cleaning, leading to packoffs around the bottomhole assembly (BHA) and stuck pipe. The formation is also interbedded with soft sand and hard cemented layers, causing severe torsional vibration and twistoffs in the BHA. Well designs and operations had been altered, incorporating larger hole sizes and control drilling to reduce packoff risks. Multiple bit runs were also optimised for each formation. This method reduced the occurrence of junked wells at the cost of individual well performance.

DWC promised to enhance performance by drilling the interval in a single run and reducing the number of trips. However, as applications of new technology encompass risk and uncertainty, the operator performed extensive analysis to quantify the likelihood and cost of failure modes and the expected reward. A key finding of the analysis was a necessity to mitigate stuck pipe. RMR offered a cost-effective method of enhancing hole cleaning to avoid this hazard. The operation was performed from a semi-submersible rig, reaching a world record depth in technical limit time without hole condition problems.

The methods discussed ensured the successful application of multiple new technologies, achieving a world record and technical limit performance. DWC combined with RMR is a world-first, and offers an effective solution for tophole drilling in the basin, and for similar basins worldwide.
Managing Chemical EOR (ASP) Effects on Formation Damage and Flow Assurance in Malay Basin, Malaysia
Authors: Yee Hon Vai , Bt Halim Nor Hadhirah , Bt Salleh Intan Khalida , Bt. A.Hamid Pauziyah A. , B Sedaralit M Faizal
Published: May 2016

The venture into various EOR process applications has been aggressively undertaken by industrial oil players to satisfy the ever-increasing world energy demand. Success of an EOR project is also governed by understanding and readiness in handling the associate EOR induced formation damage and flow assurance issues. Hence the considerations of these issues must be given great attention in the EOR project master plan.

Each EOR process application is unique and the associate formation damage and flow assurance issues are different. This paper examines the mechanisms, preventions and mitigation options for chemical EOR process induced formation damage and flow assurance issues. Fluid chemistry changes due to fluid-fluid and fluid-rock interactions among the EOR injectants, reservoir fluids and rock matrix, lead to many undesirable injection and production issues. A case study on the R&D experience of one of the major chemical EOR fields in the Malay Basin is presented. Laboratory analyses to understand and predict the severity of these issues are discussed. The major sources of problems are identified and their impacts on the success of the EOR project are discussed. A number of solutions have emerged to address these challenges. Recommended solutions are considered based on practicality, performance and economic viability.

Careful coordination during EOR project planning in handling the flow assurance and formation damage challenges and a more proactive approach to address them is our long term strategic focus which will bring significant efficiency and profitability benefits.
Corporate Social Responsibility- Methodologies, Performance and Management in Oil and Gas Industry: Case of a leading E&P Company in Colombia, South America
Authors: Baskaran V.K. , Dani K.C. , Pokhriyal S.K. , Fernandez G.J.
Published: May 2016

Mansarovar Energy Colombia Ltd. (MECL), a JV formed by India's ONGC and Chinese oil firm Sinopec, is engaged in the exploration, development and production of oil and natural gas in Colombia. Our firm owns interests in 11 fields across Colombia's Middle Magdalena basin, through association contracts with Colombia's state oil company Ecopetrol. Velasquez oil field is located in central Colombia about 160 km far away from the capital Bogota. Discovered in 1946, the Velasquez oilfield has an area of 32 km2 and was put into production from 1947.

The Valley with 45,000 sq. km has 33 municipalities, 91 rivers and approximately 1,200,000 inhabitants who make this region a potential for alternative projects that will generate social development with equity and allow improved quality of life in this prosperous region.

MECL defines CSR as "The commitment assumed for the contribution to the development, welfare and improving the quality of life for employees, their families and the community at large". Under this commitment, the company avoids any negative impact of its operations over people and its surrounding area. The management is a five stage process: Diagnostics, programs and project planning, execution, tracking and monitoring and evaluation of results.

The general objective of MECL is contribute to the economic development of the population in the vicinity of Velasquez through the articulation and enforcement of contracts and agreements between private companies, state and community efforts to articulate economic, operational and sustainability to find the social, community, business and environment. Promoting social and territorial development through investment in education, health, environment using basic mechanisms of institutional cooperation, management and community participation, establishing new revenue-generating alternatives to low-income are some of our specific objectives. Our activities include literacy programs, drug prevention workshops, cultural projects, business development training, sexual health workshops, sports, education workshops for school community (parents, teachers and students), provision of school kits to students, preventive medicine health training etc. MECL invested 1.74 million USD to fulfil its responsibilities during the year 2011.
A Case Study of Detailed Computational Fluid Dynamic Modelling of Coupled Wellbore and Subsurface Multiphase Reactive Flow
Authors: Tang Qing , Tsai Kuochen , Pollard Richard , Harvey Albert , Srinivasa Mohan
Published: May 2016

A novel concept of circulating molten salt (CMS) through a subsurface formation has been developed for the purpose of in-situ upgrading (IUP) of heavy oils into lighter transportation fuels, in pursuit of its potential to substantially reduce power expenditures and CO2 emissions during the IUP process. The CMS system can utilize molten nitrate salt to transfer heat from a surface heat source down to the hydrocarbon (HC) bearing reservoir via a system of underground pipes, essentially creating a subsurface heat exchanger. Nitrate salts are known to be strong oxidizers and can react exothermally with various hydrocarbon constituents in the subsurface under certain conditions. Detailed Computational Fluid Dynamics (CFD) simulations were carried out to evaluate the consequences of an accidental release of molten nitrate salt from a failed pipe and into the surrounding formation rock. Modeling results have been used to assess:the temperature and pressure build up in the near wellbore region; andthe propagation of a reaction front in the formation and its impact on neighboring heater/producer wells.

Extensive sensitivity analyses on salt temperature, reaction rate constants, and time of occurrence were performed. The simulation results indicate that the reaction progress is likely to be mass-transfer controlled rather than kinetically controlled under subsurface conditions. Both pressure and temperature build up are likely to be moderate in the event of a large release of molten salt. The damage that a moving burning front in the formation may cause to neighboring heater pipes appears to be manageable as long as sufficient flow rate is maintained in these pipes.
Recognising and Avoiding Water-Production Intervals Using Integrated Petrophysical Methods: A Case Study from the Piceance Basin, USA
Authors: Wu X. , McHarge J.L. , Awwiller D.N. , Devlin B.
Published: May 2016

A regionally extensive tight-gas accumulation in the Cretaeous age Mesa Verde Group of the Piceance Basin, Colorado, USA has been actively developed for over a decade. Daily production has increased from under 200 MMCFD in the year 2000 to over 1 BCFD currently. However, in some parts of the basin, the commercial development of the asset is challenged by water production.

The tight gas reserves occur in a stacked, multi-sand system. It includes over 100 stacked reservoir targets distributed over approximately 5,000ft of formation vertically. Water can be produced from any of these targets geographically. Produced water can cause serious wellbore hydraulic issues and also increase water disposal cost. Therefore, recognizing and avoiding high water production zones before hydraulically fracturing is critical.

A workflow for evaluating water-production risk has been developed. The workflow includes 1) deriving reservoir properties (porosity, water saturation, etc.) from open-hole and/or cased-hole logs, 2) calibrating the log measurements with a robust core-based, grain-size-dependent permeability prediction model, and 3) using water saturation in conjunction with permeability to evaluate the likelihood of low capillary or imbibed water for individual sands. This gives a qualitative analysis of water risk on a cross-plot of permeability versus permeability-water-saturation separation (k-Sw screening) with no water production risk (bound water) to high water production risk. The k-Sw screening concept has been verified with logs and production data from over 50 wells in the northern part of the basin. The workflow helped decrease water production thereby improving the economics of the tight gas play.
Solvent-aided Steam-flooding Strategy Optimization in Thin Heavy Oil Reservoirs
Authors: Zhao David W. , Wang Jacky , Gates Ian D.
Published: May 2016

Stochastic optimization based on a simulated annealing method were carried out to determine the optimum steam and steam-solvent flooding strategies in thin (4 m) heavy oil reservoir both in the absence and presence of a bottom water zone. The steam injection pressure optimization case determined a technically feasible operating strategy. However, the cumulative energy to produced oil ratio (cEOR) realized from the optimized process is high. In comparison, the solvent-aided steam optimization case achieved an operating stratety that obtains a much lower cEOR and cumulative water-to-oil ratio (cWOR) than those in the optimized injection pressure-only strategy. We observed that a solvent channel forms at the top of the reservoir after breakthrough of solvent to the production well. The formation of the solvent channel led to oil-solvent mixing at the periphery of the channel as well as heat transfer to oil beyond the channel, which leads to better recovery performance. In the the presence of a bottom water zone, the optimized steam injection pressure optimization strategy was found to perform poorly. However, the optimized solvent-aided strategy achieved superior economics. With solvent injection, the presence of the bottom water zone enhanced mixing of solvent and oil yielding better oil recovery performance.

Background

In Western Canada, about 80% of heavy oil resources are found in reservoirs less than 5 m thick (Adams 1982). Although currently commercial thermal-based techniques such as Steam-Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) are highly successful for recovering bitumen and heavy oil from thick pay zone (> 15 m), their application in thin heavy oil (<6 m) reservoirs are generally not thought to be economically viable. This is due to the high steam-to-oil ratio (SOR) which caused by significant heat losses to the overburden relative the amount of heat delivered to the oil which renders the processes uneconomic. Cold production (CP) employs small energy input. However, the average recovery factor is typically low, usually, between 3 to 8% of the Original Oil In Place (OOIP) (Adams 1982). By employing so called Cold Heavy Oil Production with Sand (CHOPS) technique, the recovery factor can reach as high as 15% (Pan et al. 2010). However, the formation of wormholes during CHOPS operation creates new challenges for applying follow-up processes to recover additional oil beyond CHOPS.
Flow Assurance Study for a Subsea Production System with a Large-Scale Seabed Storage
Authors: Kim Juneyoung , Choi Younseok , Choi Inhwan , Kim Jakyung , Park Su-youl , Seo Yuteak , Chang Deajun , Chang Kwangpil
Published: May 2016

This study suggests a new concept of the subsea production system based on a large-scale seabed storage tank that stores the well fluid temporarily and later transfers it to the shuttle tanker through the riser. This concept was assessed to have advantages of reduction in the floater size, freedom from transportation distance, insensitivity to sea depth, and environmentally friendliness over the conventional deepsea solutions. Several flow assurance hazards for this system were expected, and appropriate design measures and operational methods against the hazards were suggested. A feasibility study was performed for an oil field which was located at 2190 m deep producing the well fluid of black oil type. The capacity of the seabed storage tank was considered to be 300,000 m3. Simulation results showed that riser diameter should be 19 inch and the insulation layer should be thicker than 100 mm.

Introduction

Subsea production systems have been devolving rapidly over last decades. At first, a fixed type platform was developed for shallow water field. At the early stages, the jacket structure platform was used for production. Later follwed the gravity based structure which withstood external force with self-weight and the jack-up rig platform which could regulate own height with hoist. As the sea depth increased, the compliant type platform was developed. At first, the guyed tower was used for production. Continuously, the tension leg platform which was moored by tendons was followed and the spar platform which was a large-diameter, single vertical cylinder bouy developed as an alternative to conventional platforms. Recently, floating type platforms, like semisubmersible platforms and FPSOs were developed for deep water field.
A Proactive Approach Towards Optimising Drainhole Placement Using "DTB" Technology in an Area Under EOR - A Success Story from Western Onshore Field, India
Authors: Singh R.L. , Keot Chandan Jyoti , Kumar N. Sanjay , Majumdar Chandan , Singh Amit Kumar
Published: May 2016

Field X is located in the northern part of Cambay basin, western onshore India. Sand-1 is the main reservoir unit in this field. Primary recovery is low here because Field X is located in the region's heavy oil belt. To increase the recovery factor, thermal EOR technique - Insitu Combustion, has been implemented in various parts of this heavy oil belt. Insitu combustion reduces oil viscosity but at the same time produces residual gases. These residual gases, called "Flue gas", accumulate as pockets in the reservoir top. The thermally altered low viscous crude can be produced efficiently through horizontal drainholes by maximizing reservoir contact and sweep radius.

Placing a horizontal drainhole in this field is a challenge in itself because the drainhole has to be maintained at a safe distance from the flue gas pockets on top to prevent premature gassing out and also at a safe distance from bottom shale.

As a solution to this challenge, "Distance to Boundary" (DTB) technology along with LWD was introduced for the first time in Field X in Well X. "DTB" technology detects the resistivity contrast at a shale-sand interface and maps the shale boundaries while drilling. The well was landed ~10m below reservoir top using LWD measurements to maintain a safe distance from flue gas pockets on top. It was decided to place the drainhole about 3m above reservoir bottom to stay away from bottom shale. The final result was a spectacular success with 311m of drainhole drilled with 100% stay in target reservoir zone. "DTB" technology tracked lower shale from ~3m and trajectory was maneuvered in conjunction with the structural changes to maintain an average distance of 3m from bottom. LWD data was used to verify sweet zone throughout the drilled interval.

This paper illustrates an exemplary case study which opens new and exciting possibilities for application of LWD and "-DTB-" technology in field X for further field development plans.
Advancing Multi-Stage Fracturing Using Horizontal JITP and Autonomous Completion Systems
Authors: Benish Tim , Angeles Renzo , Tolman Randy , Entchev Pavlin , Kumaran Krishnan
Published: May 2016

The execution and optimization of multi-stage fracturing treatments remains one of the most critical steps in the economic development of unconventional resources. Two recently developed and field tested technologies offer a step-change in fracturing operations: Horizontal Just-In-Time Perforating (JITP) and Autonomous Completion Systems. While JITP is a well-established technique (extensively used in the Piceance basin, Colorado), its application to horizontal wells is relatively new and promises improved single-zone stimulation, significantly less use of horsepower, reduced number of frac plugs, and added flexibility in water management. In addition, ExxonMobil is actively progressing its proprietary Autonomous Completion Systems that maximize surface equipment utilization by removing the need for umbilical intervention (wireline, coiled tubing, or tractors), which also eliminates the need for lubricators, lifting equipment, additional personnel and vehicles, and improves safety.

This paper presents the latest milestones achieved in the development of these completion technologies. The application of JITP to horizontal wells was recently successfully confirmed with a comprehensive pilot program that included more than 30 wells and over 1400 single-zone treatments. Likewise, Autonomous Completion Systems entail broader applications beyond perforating systems. The key enabler for this technology is the frangible downhole navigation system which is undergoing field testing. In addition, the autonomous completion components are fully friable and do not require additional retrieval runs. The use of these technologies is anticipated to create new opportunities in equipment utilization efficiency and operational flexibility to the multi-stage fracturing methods available in the industry today.
Assessing E&P and Drilling Risks With Seismic Uncertainty Analysis
Authors: Osypov Konstantin , Ivanova Natalia , Yang Yi , Fournier Aime , Nichols Dave , Bachrach Ran , Yarman Can Evren , Nikolenko Dmitry
Published: May 2016

Exploration and Production (E&P) business faces uncertainty of our knowledge about the Earth at all stages of the aggregated workflow. Every stage uses ambiguous input and generates ambiguous output that becomes input to the next stage. Thus, understanding, quantifying and tracking uncertainty across stages and disciplines are essential for the ultimate uncertainty that impacts decision-making. In particular, the structural uncertainty is derived from the model uncertainty as a result of seismic depth imaging. Whilst the underlying ambiguity can never be fully eradicated, a quantified measure of these uncertainties provides deeper understanding of the risks and leads to more informed decision making. In the past decade, with the advancement of sensor and computer technology, the seismic industry has made great improvements in data-acquisition designs as well as depth-imaging and model-building algorithms. However, the cost/benefit justification for the value of information (VoI) obtained by utilization of these technologies remains mainly qualitative. The same limitation applies to geoscience knowledge. This paper discusses how uncertainty analysis can lead to quantifying VoI and also how application of probabilistic assessment of our geoscience knowledge can lead to investment decision-making based on probabilistic appraisal. We demonstrate that uncertainty is a good metric for the value of knowledge and serves also as a unifying language for translating, transmitting, and enhancing knowledge as one E&P stage transitions to another and as one discipline communicates with another. The paper discusses a stochastic technique of this translation through evaluation of different appraisal parameters (gross rock volume, original oil in place, net primary production) as an extended application of seismic-based imaging and structural uncertainty derived from velocity model building.

Introduction and Motivation

The overall business value within an operating energy company is generated through a long chain of multi-disciplinary sub-businesses. The bigger the company and the more sub-businesses it contains, the more challenging it becomes to dissect and quantify the value of each particular sub-business, technology, and individual. Furthermore, lack of communication between different sub-business and individuals significantly hampers the overall company value. Human nature circumvents this issue as each individual tends to emphasize his or her contribution. Each sub-business represents a certain stage of the generalized E&P process and has its own discipline language and necessary inputs and outputs. These inputs and outputs might be links to different sub-businesses and disciplines with different languages. Therefore, the overall value can be easily lost or diminished in translation.
Increasing Production by Applying Simple, Field Proven Slug Control Technology
Authors: Fong Y. , Yaw S. , Groote G. , Haandrikman G.
Published: May 2016

Description

Large fluctuations in gas and/or liquid production can lead to major disruptions on the topside facilities. These fluctuations are caused by the fluid composition, geometrical layout and operating conditions of the production system. With the current trends of: Producing marginal gas/condensate and oil fields to existing facilities with subsea tie-backs, Developing more deepwater fields, Producing from existing production facilities towards the end of field life cycle, irregular production or slugging pipeline systems are observed more frequently. Therefore, slug mitigation techniques may achieve significant value impact on the business. The most recent technology in Shell for slug control is the Smart Choke. This technology consists of a single control valve that is installed between the riser top and the first stage separator. It is an active slug control device acting on gas and liquid surges without the requirement of phase separation upstream of the control valve. The basic control mechanism maintains a constant total volumetric flow at the system outlet. Furthermore, a detection algorithm is incorporated, which detects 'liquid only' or 'gas only' production. Based on this, the controller will switch between the different control modes for slug control. Additional to this flow controller, a slow valve position controller and a differential pressure override controller is used to ensure that the output of the volumetric flow controller remains in the range of the normal (or desired) operating valve position.
Using Diffusion Maps for Latent Space Analysis on Seismic Waveforms of Incised Valleys in the Anadarko Basin, Oklahoma, USA
Authors: Bratberg Ivar , Wallet Bradley C. , Davogustto Oswaldo
Published: May 2016

In this work we present a new method for latent space mapping based upon inter-point similarities. This method, diffusion maps, has a number of nice qualities compared with previous methods including the fact that it is based upon inter-point similarities rather than a Euclidean space. We then demonstrate application of this approach to mapping an incised valley system from the Anadarko Basin, Oklahoma, USA.

Introduction

Multi-dimensional data is commonly encountered in attribute analysis where the desire is to combine several attributes with complementary properties. As geophysicists, we tend to view attribute spaces higher than four dimensional as being undesirable as they cannot be visualized using common color models such as ARGB space. Furthermore, mathematical considerations such as the Curse of Dimensionality (Bellmann, 1957) make working in lower dimensional space necessary.

(Guo, Marfurt, Liu, & Dou, 2006) discussed an unsupervised learning method for doing dimensionality reduction of attributes using Principal Component Analysis (PCA). While this method has been shown to be useful in a broad range of applications, they are limited in their ability to capture non-linear structure in multidimensional attribute space. Retaining this non-linearity is important as data sets generally present a heterogeneous mix of latent processes that, taken as a whole, are unlikely to be well represented by a single low-dimensional linear manifold.

A number of non-linear methods of manifold learning have been applied to seismic attributes and waveform modeling (Wallet & Marfurt, 2008). Self organizing maps (SOM) is the best known of these approaches, and it is available in a number of commercial products. (Wallet & Perez, 2009) also demonstrated the use of a statistical method, generative topographical maps (GTM).

(Wallet & Perez, 2009) applied diffusion maps to the problem of modeling well log data. They noted that the high computational demands of diffusion maps was an impediment to scaling to reasonable sized seismic problems. In this paper, we present an estimation method that deals with this problem.
Coiled Tubing and Well Testing Experiences on Sichuan Horizontal Shale Gas Wells
Authors: Stolte Chris , Wu Chris , Carroll Darryrl , Shiqian Wang
Published: May 2016

Shell China, in partnership with PetroChina Southwest began horizontal completions in its Sichuan shale gas project in 2012. By the end of 2012, two vertical and three horizontal wells were drilled and completed in the Lower Longmaxi Hot Shale interval. Performance has continuously improved throughout the implementation of the completions program1 and significant technical and operational challenges were overcome.

The three horizontal wells were drilled with progressive horizontal lengths. On the third and longest well in the sequence, difficulties were encountered when attempting to mill plugs in the horizontal section. Well pressures were in excess of coiled tubing limits and the plugs could not be milled. As a result, the well was produced with flow-through plugs in place until the well pressure could be reduced and a higher pressure coiled tubing reel was available. Due to the high well pressures observed, additional measures were taken to reduce operational risk during the coiled tubing millout and ensure a successful operation. The flowback package design was improved by utilizing hydraulic chokes in place of manual chokes and a dual-plug catcher system was installed in the flowback package. In addition to improving the flowback package for millout operations changes were made to the flare system. After the coiled tubing millout was completed, difficulties were encountered during the full phase well test requiring the horizontal flare to be replaced with a vertical flare due to HSE concerns. The challenges experienced during this operation and the improvement aspects gained will be utilized in the completions planning and execution of the next phase of horizontal wells.

This paper highlights the coil tubing millout, flowback, and well test learning experiences gained during the completion operations of the second and third horizontal wells.
Geological Reservoir Modelling in an Unconventional Play Setting: Appraisal of the JinQiu Block, Sichuan Basin, China
Authors: Mueller Dietmar , Rolph Alan , Ha Kwong Tak , Zhao Da Hua , Carl Brian S. , Liao Xi , Xu Long
Published: May 2016

Fluvial-lacustrine deposits of the Xujiahe Formation are the primary reservoir target for an ongoing appraisal project in the northwest Sichuan basin. The late Triassic clastics are comprised of six members T3×1 to T3×6. The amalgamated channel sandstone sections of the T3×2 and T3×4 members may form an "inefficient" Basin-Centered gas play charged from downdip source rock while the calcarenites, coaly shale, and calcareous siltstones of the T3×3 and T3×5/6 are possibly charged by local source rock.

Static modelling helped to improve understanding of production history for un-fracced vintage wells and early production behavior of newly drilled appraisal wells. Well sector models (scale of ~1×1 km) were created for this purpose.

The ability to predict areas with low water production is crucial for the economic feasibility of Xujiahe development. Water saturation versus porosity cross plots provided key input to saturation models in static models. The cross-plot method tentatively helps predict well productivity but further calibration is necessary.

Introduction

The Xujiahe formation consists of sequences of coaly calcareous siltstones and shales alternating with high Net/Gross (N/G) quartzo-feldspathic arenites. In the study area, the Xujiahe Formation ranges from 900–1300m in thickness, deepening and decreasing in N/G towards the NW. These changes reflect a facies change from stable platform in the SE Sichuan basin to a foredeep to the NW.

The Xujaihe formation is stratigraphically subdivided into six members T3×1 to T3×6 across the Sichuan basin. In the study area the uppermost T3×5 and T3×6 members consist of interbedded shales, thin coals, calcareous silstones and calcarenite sandstone. Although separated elsewhere in the basin, in the study area the T3×5/6 are combined because no clear boundary is recognizable. Xujiahe members T3×3, T3×2Lower and T3x1–3 are similar in lithology to the T3×5/6. The depositional environment of these coaly intervals is interpreted as shallow lacustrine/marsh environment with ephemeral meandering rivers. Calcarenite sandstones occur as isolated 10–50m thick intervals and are difficult to correlate. Calcarenites are interpreted to erode underlying shales, siltstones and thin coals, an assertion supported by limited 3D seismic. Calcarenite log porosity ranges from <3–5%. Calcarenite sandstone intervals do not contain observable wet zones.
Improved Methods and Workflows for Multi-Zone Stimulation
Authors: Nygaard Kris , Gosavi Shekhar , Entchev Pavlin , Zhou Fuping , El-Rabaa Wadood , Shuchart Chris
Published: May 2016

Economic production from many low permeability unconventional reservoirs has been enabled by the ability to propagate multiple stimulation treatments per well and from multiple wellbores located on a single pad or platform. A variety of design procedures and mechanical means have been developed to create improved connections to the reservoir, reflecting ongoing innovation in improving stimulation effectiveness while enabling reliable treatment placement and completion cost reduction. Both modeling and interpretation tools have been developed to predict, assess, and optimize stimulation treatment design and placement.

Successful multi-zone stimulation requires evaluation and selection of many options - ranging from rock property design assumptions to methods of zonal isolation and fluid diversion to the efficient use of water and equipment deployment. Hence it is essential to incorporate strategies to integrate multi-disciplinary technology, operational data, and economic optimization in the workflows to achieve the best results. These strategies also require the flexibility to adapt various existing and emerging technologies within the unconventional reservoirs and account for the local operating environment and conditions.

This paper examines the fundamental elements driving multi-zone stimulation effectiveness based on integration of extensive field experience and research in reservoirs requiring multi-zone stimulation to unlock their economic potential. Tools and workflows will be illustrated that have improved multi-zone stimulation effectiveness, enabled significant operational efficiencies, and have led to enhanced well performance and resource recovery.

Introduction

Worldwide, substantial oil and gas resources are contained in low permeability formations. Many of these resources are characterized by thick intervals and/or multiple reservoir targets. In addition, some form of stimulation such as matrix acidizing, proppant fracturing, or acid fracturing is required to effectively and optimally produce these resources. However, the increased geologic and reservoir heterogeneities present in these resources can lead to substantial complications to the stimulation treatment operations, and reduction in stimulation effectiveness. To address these issues and enable more efficient resource recovery, during the last decade, ExxonMobil has focused on developing fit-for-purpose design methods, completion systems and procedures to enable optimization of stimulation treatments.