bluuebunny/crossref_metadata_2025 huggingface dataset:
A Decision Analytic Approach to Geosteering Operations
Authors: Kullawan K.. , Bratvold R.. , Bickel J.E.. E.
Published: June 2014

The technique of geosteering has been widely adopted in the petroleum industry for proper wellbore positioning. The benefits of geosteering have become more pronounced as drilling environments have become more complex. Geosteering-related technologies, such as downhole information-gathering tools and real-time data-transmission and data-analysis applications, have been continuously and significantly improved to support geosteering decisions. However, the full value of these advancements has yet to be realized.

Because of uncertainties in predrill geological models, information gathered while drilling is applied in making real-time reservoir-navigation decisions. To achieve an optimal result requires a series of high-quality decisions regarding well-trajectory adjustment.

Interestingly, geosteering-related literature does not demonstrate that the industry has applied a logically consistent approach for making geosteering decisions. Common practice, as described in the literature, does not clearly and quantitatively state measurable objectives, key underlying uncertainties, or relevance between underlying uncertainties and real-time information. Furthermore, it is unclear how a specific geosteering decision is being reached. Lacking a systematic and transparent framework for supporting geosteering decisions, the current approach is unlikely to result in optimal decisions for placing the well in the best possible location.1

In this paper, we introduce and discuss a decision-driven approach to the geosteering process. The main contributions of the paper are threefold: (1) a review of 46 SPE papers on geosteering, including a discussion of the main features of current geosteering methods; (2) the development and discussion of a decision analytic framework to support high-quality geosteering decisions; and (3) implementation of Bayesian inference techniques to consistently update ahead-of-the-bit reservoir uncertainties while behind-the-bit data are gathered in real time. The new framework relates real-time information to the key reservoir uncertainties and provides an unbiased and consistent approach for making high-quality geosteering decisions.
Monitoring Well Performance and Rate Compliance in Real Time: A Case Study
Authors: Al-Dulaijan A. K. , Al-Thuwaini J. S. , Alali A. M , Towaileb H. A. , Al-Daif H. Y.
Published: June 2014

This paper presents an approach to monitor, support and optimize reservoir performance in real time using an Intelligent Field. The approach is demonstrated with a case study based on the experience of implementing Intelligent Field solutions in one of Saudi Aramco's onshore fields. The field is equipped with surface and subsurface instrumentation to capture and deliver real time data. The case study highlights the critical process of utilizing Intelligent Field data to monitor compliance between actual well production/injection rates and the reservoir management guidelines.

The case study shows a giant field with under-saturated, heterogeneous and peripheral water-flooded reservoirs. A fundamental part of reservoir management best practices is to balance the pressure distribution within the reservoir and to ensure uniform flood front movement in the field through maintaining a calculated voidage replacement ratio (VRR). Due to the heterogenous nature of the reservoirs, the voidage replacement level is different from one area to another, which adds complexity in designing and monitoring the optimal injection-production ratios and guidelines. Frequent violations of these guidelines could lead to unwanted consequences, such as early water breakthrough and undesired reservoir pressure.

The demonstrated workflow starts by assigning monthly wells production/injection guidelines based on the field target rate, well status and reservoir/well performance. Then, the workflow captures the real time flowing wellhead pressure and temperature to convert them through IPR/VLP models to rates. Then the calculated rate per well is compared to the assigned target rate per the production/injection guidelines. Responsible engineers receive compliance reports twice a day to take remedial action as needed.

Implementing this workflow helped both reservoir and production engineers to monitor changes in well performance and ensure the compliance to the target rates in real time.
Gas Lift Optimization by Real Time Monitoring using SCADA System
Authors: Ezzine Mohammed
Published: June 2014

By depletion of reservoir, water encroachment occurs and wells were shut-in by heavy column and salty water deposition in the tubing, the decision of lifting wells was taken and wells were converted to Gas-Lift, by injecting Gas and Water in the same annulus to straighten up the field daily production about 30% (2000 m3/d).

Current Production is reached 1500 m3/d, caused by dynamic change in reservoir and operating parameters, the necessity to introduce an innovative technology to improve recovery is strongly recommended.

Data collected in real time from field is used and integrated in nodal analysis software, to optimize the Gas-lift allocation and maximizing wells production vs. Gas injection.

Examples from field are used and a case study of integrated system is illustrated.

Data Management system will be fed automatically from the field, this will increase accuracy by eliminating human error.
Strategies Accelerating Progress of Digital Oil Fields (DOF)
Authors: Mubarak Saeed M. , Winford E..
Published: June 2014

The petroleum industry has recognized that DOF technologies make it possible to provide more efficient, accurate, and timely information to decision makers. Business value has already resulted from some DOF technology implementations, but there is still much opportunity to be captured and many lessons to learn to take full advantage of the digital oilfield.

The infusion of digital technologies into hydrocarbon upstream industries has significantly impacted the E&P business environment. In this new environment, it is imperative for organizations and their leaders to formulate and deploy strategies that strengthen: Organizational structure and capabilities to support the use and care of DOF.Comprehension business needs and expectations through clear communication.Competencies of industry professionals to improve collective performance.

Pioneers are exploring venues to create adaptive business environments capable of integrating this technological change into their strategies and business value architecture. Continued improvisation of implementation methods can result in the perception that DOF is just very uncertain and wasteful to warrant significant time, attention, and resources. This paper describes a more ordered and disciplined implementation methods that may be used to facilitate tangible DOF progress facilitating the management of assets more intelligently.

This paper also undertakes the mission of uncovering various strategies and technologies for leveraging knowledge, experience, and decision making that could accelerate the progress of DOF implementation. Some of the content of the paper is based on actual survey results, on field observations, and on rational speculation about future trends and advances in DOF technologies and their implementation.
Production Optimisation of a Long Horizontal Well Using Permanent Down-hole Distributed Temperature and Pressure Monitoring and Surface Controlled Zones
Authors: Carlsen Magnus , Kofoed Sara Sparre , Rijkels Lex , Marketz Franz
Published: June 2014

Optimizing production and understanding inflow from long horizontal wells in tight chalk reservoirs has traditionally been difficult. The horizontal sections of these wells have been typically segmented into four to eighteen zones, driven by completion, stimulation and reservoir management requirements. Surface controlled sliding side doors have been used in a number of wells to control the zones for production optimisation, but permanent down hole monitoring of each zone had not been undertaken in the Danish sector so far.

The subject of this paper is the installation and application of zonal pressure gauges and distributed temperature sensing in a recently drilled long horizontal oil producer in the Danish sector of the North Sea. Despite a very challenging trajectory and reservoir pressure variations along the horizontal section the well was drilled to 24,000 ft measured depth and equipped with permanent downhole monitoring and control capabilities. The horizontal reservoir section was segmented into five zones. In each zone a surface-controlled sliding side-door and a pressure and temperature gauge were installed. A fibre-optic cable for distributed temperature sensing (DTS) along the upper four zones to a depth of around 15,500 ft was installed as well. The upper four zones also contained an extra coiled-tubing operated sliding side door for restimulation purposes.

After completing the well each zone was matrix acid stimulated. Stimulation monitoring with DTS allowed quantification of zonal acid coverage and identification of the scope for re-stimulation. During initial production of the well the pressure and temperature gauges in each of the zones proved valuable for start-up operations. Cross-flow between zones was identified and this knowledge was used for improved management of commingled zonal production.

This paper describes how temperature and pressure data from each zone has been used for well production optimisation, in sometimes unexpected ways. The combination of being able to react without intervention using the real-time data has proven to be critically important and supported more efficient operations.
Smart Water Management as part of Supply Chain Logistic for Source Rock Development
Authors: Olsen D. K. , Weitner M. , Olson D. C. , Perino J. O. , Womack D. M.
Published: June 2014

Source rock unconventional play development for both oil and gas (O&G) has become economically feasible because of two enabling technologies: horizontal drilling and hydraulic fracturing. This opens a much larger hydrocarbon resource than conventional oil & gas found within traps and covers a much wider surface area than historic oil fields - often in areas unaccustomed to petroleum production and lacking the required infrastructure to support production. To generate the required drainage channels, these tight source rocks have to be fractured to generate flow paths that permit economic production. Water has become the default carrier fluid required to transport proppant required in fracking because of its relative ease of handling, low cost and wide availability. Managing the logistics of water in the supply chain can be a complex and challenging process, particularly given its close scrutiny by regulators and the public. Given the challenges and complexity however, it is still often handled by a series of spreadsheets and project planning software and usually managed under a separate production schedule due to the long lead times needed for permitting, engineering, construction, filling and the required pumps and monitoring equipment. Unlike municipal and utility water systems, water systems for well stimulation are mobile or temporary as end use points move from pad to pad during development of hundreds of wells per year per company. Sourcing, transport, use, reuse and disposal of water vary from basin to basin posing significant challenges and complexity in the management and treatment of frack and produced water.

In this paper, the authors discuss Smart Water Management (SMW) in source rock play development primarily for North American and tight oil and gas formations, but with insights that apply worldwide and to the broader field of unconventional development including coal bed methane. SMW incorporates the processes and methods used to more intelligently manage scheduling and logistics in forecasting, supply, transport, storage, use, fracking, flow-back and produced water treatment, reuse, and disposal along with solids and brine, and chemicals handling. Thus optimize water availability, minimize fresh water use, reduce the major costs and the transportation impact, and improve spill/leak detection and regulatory compliance.
Collaborative Work Environments in Shell - Global Scale, Learning and Evolution
Authors: van den Berg Frans G. , McCallum Giles A. , Graves Matt , Heath Elizabeth , Evans Allen
Published: June 2014

With seven years experience, Shell has concluded that Collaborative Work Environments (CWEs) provide significant benefits in the production surveillance and field management area. As a consequence, the company has embarked on a wide scale implementation in all its major existing and new assets around the world. Many of these are now in place. The environments have enabled faster and better decision making by improved communication and easy sharing of relevant information and data. Business benefits include increased oil production, longer equipment life, improved HSE and lower operating cost.

The concept of CWEs has evolved, gradually expanding from original real time monitoring centres. Currently, centres for production surveillance and field management and drilling monitoring centres are the most common.

The implementation programme has evolved, converging on standard solutions and designs. Standards are now available for processes, disciplines and organisation to be involved, the required information and data, the audio visual technologies and for the physical facilities, the collaboration rooms and offices. In each asset, an assessment identifies the key aspects relevant to the asset and formulates the best collaborative solution for it.

Considerable learning has been obtained in various aspects, such as improved access to global expertise, introducing standard processes and ways to sustain the solutions and the benefits.
Creating a Wireless Digital Platform to Accelerate and Improve Upstream and Downstream Operations
Authors: Pluis René
Published: June 2014

This paper gives an overview of the deployment of industrial wireless technology to create a wireless coverage (called a domain). Some of the business drivers are being discussed and some of the implementation challenges are discussed in the section about the implementation. At the end an example project is being described.
Delivering Access to Expertise in Upstream Oil and Gas Operations
Authors: Alqadi Eyad
Published: June 2014

Oil and Gas upstream operators are tasked with maximizing rates of production, availability and quality, whilst at the same time minimizing cost of production. Addressing this with a dwindling pool of expert resources following the "great crew change" makes the challenge even greater. Consequently, achieving increased utilization of expert resources will be critical to the future wellbeing of upstream operators.

This paper will initially explore a number of use cases where technology-based solutions can be used to "take the problem to the expert" rather than the "expert to the problem". The provision of long distance/remote access to expertise in real-time using integrated voice, video and data solutions will be shown to derive business benefits in terms of: Reducing the time taken to reach decisionsGiving access to a wider range of experts, thus improving the quality of decisionsReducing the cost of expert interventions by avoiding expensive and time consuming travel to rigs, wellheads and processing facilitiesIncreasing the utilization of experts by enabling them to work simultaneously on multiple issues potentially spread across multiple assets

The paper will then go on to address the key elements of the technology architecture required to deliver this remote access to expertise. It will also demonstrate how the need for standard reference communication architectures has to be tempered with a requirement for flexibility to accommodate multiple use case scenarios and operating environments. This paper will be based not only on the authors’ organization’s own research and development in this field, but also on practical experience implementing wide area collaboration technologies in upstream operations in a number of international and national oil companies. As a consequence it will include not only information on leading edge developments in collaboration technology, but also best practice based on practical experience in the field.
Live Well Models a Tool for Production Optimization
Authors: Rachapudi R. V. , Haider B. Y. , Al-Mutairi T.. , Al Deyain K. W. , Al-Yahya M.. , Shakeel A.. , Qureshey K. R. , Harith Mikhail
Published: June 2014

Continuous well performance monitoring plays a key role in making decision related to well workover and production optimization. Well parameters and corresponding rates over a period of time will represent the change in well performance. Live Well models are useful for estimating the continuous well production rates. Well models become live if they get updated with changing fluid and reservoir properties along with proper calibration to latest well conditions.

In general industry practice is to update the model manually; this is a tidious and time consuming process. Umm Gudair Field Development team implemented a real time system using available resources that integrates and runs workflows between corporate data base, well surveillance data base and well models. Workflows were implemented as part of the real time system to calculate the well parameters from sensor readings and update the models to run on daily basis, such that the models become live and production rates will be estimated.

The daily output generated from the workflows is basically updated well models and parameters along with production estimation report that will get emailed to users. The daily report contains the information about well status, potential, reasons for well closure etc. The workflows are intelligent enough to flag the need for model calibration and surface rate measurements. The daily estimated well parameters will be saved back to database for visualization. In conclusion, real time system was implemented to keep the well models live and useful as a tool for optimizing the oil production, improving the ESP’s run life and delaying the well intervention requirements.
PDO’s Journey Of Process Control Optimisation - A Look Back To The 15 Years Of Existence Of The PCO Team - Challenges, Achievements, Training, Future
Authors: AL-Harthy Hilal
Published: June 2014

In EP industry, the dynamic behavior of well and process facilities is hardly considered. As a consequence, the full design capacity of the plant is under-utilized and at the same time extension projects/ de-bottlenecking are easily justified. Petroleum Development Oman (PDO) solution to this has been the creation of the process control and optimization team which continuously reviews and optimizes the dynamic performance of the production processes in view of improving the equipment/plant availability, enabling smoother operations, freeing-up hidden capacity and operating closer to equipment/plant constraints.

The Process Control & Optimization (PCO) team has also been active in developing control innovation solution to different process dynamic behavior problems and input to engineering project for robust process control design and flawless start up. Typical control solutions have saved the company millions of dollars in waste elimination and in providing in house control solution to engineering design projects. Some of these intelligent solutions are a key enabler of successful execution of Well, Reservoir and Facilities Management (WRFM), Process Safety Management (PSM) and Production System Optimization (PSO).

This paper presents the PCO journey in PDO with a look back to the 15 years of existence of the PCO team with main focus on people, process, technology and sustainability.
The Use of KPIs to Measure Performance Improvement in a Collaborative Work Environment
Authors: Ajmi Jasim , Simmonds Keith
Published: June 2014

Description

One of the perennial challenges of a Collaborative Work Environment deployment is how to demonstrate and quantify the value of benefits that arise from the investment. There does not appear to be a consistent approach to measuring the benefits either at the point of implementation, or on an ongoing basis.

Indeed most oil companies have to rely on just some form of a Post Implementation Review to provide a snapshot of the performance and to extrapolate benefits and savings based on this.

Application

While this approach will enable some measure of effectiveness at one particular point in time, this does not help on an ongoing basis. Considering the costs in terms of time and money typically invested in such implementations, a more precise form of measure is required for management purposes.

This paper looks at the approach used by PDO, the range of performance measures and KPs that were considered and that have been adopted. This approach is now being used across PDO’s the enterprise wide deployment of their second generation CWEs across Oman.

Results

From the work carried out at PDO, a number of measures were identified that enable both the effectiveness of the implementation and the operational performance to be reported on. The operational performance measures are such that these are used across all ten assets and enables regular monthly metrics to be recorded and used for management purposes.

Observations

The work and experience to date has highlighted a number of key learnings

Conclusions

From the work carried out a number of measures were identified that enable both the effectiveness of the implementation and the operational performance to be reported on. While these have not been easy to agree and do require a level of collect and assess on a regular basis there is real value from this work. The operational performance measures are such that these are used across all ten assets and enables regular monthly metrics to be recorded and used for management purposes. These will continue to be used over the lifetime of the CWEs.

Significance of Subject Matter

This demonstrates that a structured and considered approach taken during the deployment of a Collaborative Work Environment can be used to help to provide both a measure of the actual implementation as well as more importantly a means to monitor to assess the value and benefits being provided once in live operation.
Bridging Operational Information with Real-Time Data: Enhancing Real-Time Monitoring Engineer‘s Situational Awareness
Authors: Borjas Ricardo , Hamzah Mohammad Khairi
Published: June 2014

In recent years, oilfield companies have realized the value of real-time data and have set up real-time centers to monitor multiple wells in a given area remotely. With the advancement of rig communications, several wells can be streamed to these real-time centers where they are monitored by real-time engineers.

In addition to the data streamed from both surface and downhole sensors to real-time centers, operational information is communicated electronically via emails, daily reports, and meetings; this information must be manually entered or interpreted by real-time engineers. We have observed that this takes precious time away from the real-time engineers’ core function of monitoring.

However, as real-time centers mature, there must be a focus on merging operational information with real-time streaming data to reduce communication lag time and raise the real-time engineer’s situational awareness at all times. Coupling business systems with real-time monitoring software will have an immediate impact on the entire process, reducing communication time and instantaneously syncing the real-time center with rig operations.

A first step towards this goal is to provide the real-time monitoring software with the ability to pull in and merge operational data with streamed data from the wellsite. Operational data can then be viewed on demand and updated automatically as well as visualized together with the streamed data through predefined dashboards. Up-to-date operations information changes will be synchronized to the real-time monitoring systems and brought to the attention of the real-time engineers.

As a result of the implementation, a step change has been observed in the situational awareness of real-time engineers, improving their interpretation of the current situation and their influence on operational changes. Finally, there remains a need to move towards digital information exchange between these systems in both directions to provide a more collaborative environment.
Delivering Real-Time 220,000-Channel 3D Seismic Experience for the First Time in Kuwait
Authors: Joseph Binu Thomas
Published: June 2014

The need to create a real-time experience was crucial to remotely show a seismic acquisition system at the recorder, located 35 km away from an event venue built in the desert. This was achieved through live audiovisual communication for 200 participants. Major challenges faced were: the event location was outside the scope of conventional IT support; the large number of participants; 30-day time constraint; conducting a feasibility study in the field; conduct a continuous test until a proposed in-house solution was functional; and otherwise integrate with an alternative third-party-produced backup solution.

The proposed solution describes how a packet-switched network and H.323 signaling protocol operating on an IP-based network was used for videoconferencing (VC) between two remote locations. The two main components of the signaling protocol were the registration admission status that controls the entire video network, used between the gatekeeper and the VC unit, and the Q.931 responsible for establishing and cancelling the connection between the VC units. The remote screen- sharing tool for broadcasting the seismic acquisition system uses the secure socket layer (SSL) for communications security. The key exchange protocol used was remote access service, while the data encryption is AES256-SHA used by means of the web browser that supports it. A follow-up with the supplier was made to double the current bandwidth to prevent a drop in the network performance.

The successful outcome of the event demonstrated how IT can contribute outside their normal scope of work by providing event design and coordination, and can succeed in helping participants make informed decisions by facilitating a real-time seismic experience that saved the business USD 30K.

This paper depicts the high value of IT by delivering business solutions.
Upstream Workflow Transformation in a Mature Joint Venture Asset:- Design, Implementation and Adoption for Value Creation
Authors: Adeyemi O. S.
Published: June 2014

Production optimization from mature assets with limited well instrumentation, aging facilities and depleting reservoir energy is a big challenge. The economic viability of retrofitting these assets to enable - instrumentation for seamless data capture, remote transmission, storage and integration with engineering applications is sometimes challenged.

A methodology and practical approach for designing and implementing integrated field (i-field)in a mature joint venture asset in Chevron Nigeria is presented in this paper. The various fields span several kilometers cutting across different terrain including land, swamp and shallow offshore locations with maximum water depth of 150 ft. The first well spudded in December 1963 came on production in March 1965 and still producing 48 years later (in 2013). There are more than thirty fields currently producing across over 2.2 MM acres. The extent of the geographical spread not only comes with different terrains but also presents complexity with design and application of i-field within Chevron Nigeria Limited (CNL).

The identification, prioritization and deployment of petro-technical transformational workflows were discussed. The implementation of a robust IT architectural foundation is pivotal to the adoption of existing and emerging solutions. The methodology for ranking the assets was largely based on current production and remaining reserves, existing downhole or wellhead instrumentation, availability of SCADA network and ease of implementation through a proof of concept (POC). Using a phased approach, multiple components of the i-fieldprogram were implemented. The first wave of solutions recorded a value of $2.5 MM in 2012 from better collaboration, production optimization, and management by exception. In addition, significant savings resulting from improved productivity, safety and operation excellence was attained in several assets/fields that are more than 40 years old. The overall impacts of these deployments have resulted in early gains resulting from reduction in OPEX and loss production opportunity (LPO) and improved reliability.

Some of the challenges encountered include ability to retrofit existing wells and facilities especially with diminishing reserves and aging facilities. Value proposition for marginal field and lack or limited infrastructure related to bandwidth for communication was a big challenge. In addition, best practices and lessons learned for development and deployment of i- fieldinitiatives in mature brown fields are presented.
Tangible Values for Running Distributed Temperature Survey (DTS) as Part of Stimulating Multi-Lateral Injection Wells
Authors: Al-Gamber S. D. , Mehmood Sajid , Aramco Saudi , Ahmed Danish , Burov Anton , Brown George , Barkat Souhaibe , Shrake Gwynne
Published: June 2014

Proven to maximize hydrocarbon production or well injectivity, horizontal multilateral completions have witnessed growth both in number and complexity over the years. These well types brought challenges with respect to well accessibility for rigless well intervention, and the ability to access these wells has been developed using coiled tubing (CT) to enable operations, such as reservoir stimulation, to be carried out.

One of the main challenges is to identify and access each lateral, to be able to perform the stimulation to maximize well production. This challenge has been encountered in Saudi Arabian multilateral wells, which are drilled in a carbonate reservoir with an open hole (OH) completion and where the laterals are typically left with a high formation damage (skin effect) after drilling, thus requiring stimulation to improve their performance.

At present there is no single technique for lateral identification without tagging TD. In this paper we describe how a combination of multilateral tool (MLT) along with CT downhole measurement system is used to locate and access laterals, selectively acquiring a gamma ray profile across each of the laterals, then optimizing the stimulation operation using distributed temperature survey (DTS) measurements.

This paper discusses the planning, execution and evaluation of the results in a stimulation job performed on an open hole multilateral water injector employing a CT with fiber optics that enables a real-time downhole measurement tool (pressure, temperature, casing collar locator, gamma ray) and MLT. The results highlight the effectiveness of the technique in maximizing the wells performance.
The Art of Intelligent Energy (iE) Part 2 - Insights and Lessons Learned from the application of iE between 2009 and 2012.
Authors: Edwards A. R. , Helm P.. , Dhubaib T..
Published: June 2014

Intelligent Energy (iE) has been a major performance improvement initiative within many oil and gas companies for much of the last decade. It is therefore surprising to find that, although many companies have been successful, many continue to find it difficult to scale and sustain the change in the new way of working enabled by iE. This paper builds on the original paper presented at the Intelligent Energy 2010 conference and draws on the authors’ most recent experience of the practical implementation of iE in major oil and gas companies both international and national.

This paper gives insights and lessons learned into the skilled practice of the application of iE drawn from experiences major oil and gas companies. It will explore such topics as: Scope of iE implementationHow do you scale iE?How do you sustain iE?Big bang versus evolutionary approachContracting strategies for iELeadership and management of changeScaling of iE across an organisationThe role of a central programme officeWhat is next for iE?

It will also draw attention to some of the numerous pitfalls to be encountered along the way. It will finish by highlighting some of the new challenges and opportunities in iE.
First Openhole Hydraulic Fracturing Treatment Using Diverter Technology in India
Authors: Adil Faraaz , Pande Karan , Raina Bhavna
Published: June 2014

This paper discusses the hydraulic fracturing (HF) treatment of a tight gas well owned by a major power service company in India. The objective was to perform a HF treatment on the openhole (OH) section to assess the reservoir potential for future development work. The success of this treatment could unlock the oil and gas reserves in this area of the country, which are estimated to be massive.

The fracturing treatment of the tight gas reservoir was to be performed under these conditions for the first time in the area, so there was no previous information to help design the treatment nor predict the result. Injectivity and mini-frac tests were performed to analyze the reservoir properties before designing the final fracturing design and execution.

One of the major challenges was to perform the fracturing treatment on an OH section under extremely strenuous operational deadlines, which eliminated the options of using any more suitable well completion methods. Thus, it was proposed to use a diverting agent in the fracturing treatment design to help maximize the stimulated reservoir volume (SRV) in the OH section. The objective was to create at least two to three multiple independent fractures in the OH section. The challenge was to manage the injection rates and deliver the diverter accurately to the bottomhole to create a bridge at the open fracture, isolate it, and initiate a new fracture. This paper discusses this process, and the the lessons learned during the treatment execution.

In addition to the description above, the following issues had to be addressed before progressing to the primary fracturing treatment: heavy mud was in the wellbore and OH section, this was a low-permeability reservoir, operator's Christmas tree pressure rating was low, this was a deep well with a long OH interval, there was an extremely short operational execution deadline, and this well's close proximity to an adjacent well, leading to possible communication between the wells.

This paper discusses the fracturing analyses performed to design the fracturing treatment, the ideologies used for performing the successful fracturing treatment using diverter technology, and the results achieved using this technique.
Horizontal Well Development in Unconventional Resource Play Using an Integrated Completion and Production Workflow: Delaware Basin Case Study
Authors: Sharma Anoop , Yates Malcolm E. , Pope Tim , Fisher Kelvin , Brown Randy , Honeyman Les , Bates Bradley
Published: June 2014

Horizontal wells give a great opportunity for maximizing the potential of unconventional resource play developments by providing enhanced reservoir contact but present multiple challenges in the process due to the heterogeneous nature of the unconventional reservoir rock.

This study covers the implementation of an integrated completion and production workflow to optimize a horizontal well development project in the Delaware Basin located in Reeves County, Texas. By undertaking a vertical well pilot logging program, the acreage was evaluated for petrophysical and geomechanical properties using advanced geo-chemical and full-wave sonic tools to quantify reservoir quality (RQ) and completion quality (CQ), respectively. Detailed fracture simulations were performed at multiple depths to locate the optimum landing point that maximized reservoir contact. Incorporating the key findings of the wellbore stability analysis, the well was geo-steered using a rotary steerable system (RSS) and a logging-while drilling (LWD) resistivity tool that placed 100% of the lateral in the target zone. Further completion simulations were performed to determine a perforating and staging strategy which would optimize the number of stages. The flow-channel fracturing technique, which provides a novel approach for achieving fracture conductivity, was also implemented on the studied well to significantly improve the effectiveness of the fracture stimulation treatment. Fracture diagnostics, detailed post fracture modeling, and production analysis techniques, which utilized rate-transient analysis and history matching, were performed to provide better understanding of the effectiveness of the stimulation treatments (fracture lengths/conductivity), thereby allowing further optimization of the stimulation program.

This study has demonstrated how the implementation of an integrated design and evaluation workflow can optimize the overall well production performance as well as reduce drilling and stimulation costs in unconventional resource play developments.
Getting Back to Basics: Using Routine Drilling Mud Logging Data for Reservoir Characterization
Authors: Hayton Shaun , Tischler Gerold
Published: June 2014

Reservoir characterization in unconventional reservoirs can be problematic due to the magnitude of uncertainties in the measurements being made. While significant advances continue to be made in logging tool capabilities and the integration of detailed core and petrophysical analyses, the utilization of these results on a routine basis for reservoir characterization during development using horizontal drilling is cost prohibitive. Additionally, time delays in obtaining results from core analysis make this approach inappropriate for operational situations.

Detailed reservoir characterization in horizontal wells to design targeted hydraulic fracture stimulation is a fundamental aspect of Saudi Aramco's forward plan for developing unconventional shale and tight gas sand reservoirs. A method by which detailed reservoir characterization can be undertaken in a cost-effective and timely manner is required.

This paper describes the results from the trial testing of the Geological Differential Method (GDM). The trial uses routine drilling parameters, mud gas data, lithology data and associated core calibrated petrophysical analyses from multiple (model) wells to determine routine petrophysical properties such as porosity and fluid/gas volumes in unknown (prediction) wells. This new technique is fundamentally different from existing neural networks and other statistical based systems. Rather than using input data to provide a basis for informed inference or extrapolation, GDM uses the input data as part of a predictive process. This paper summarizes the work flows and results of three separate projects involving nine lower Paleozoic exploration wells and a variety of unconventional targets (shale and tight gas sands). We describe the work flows in general and show comparisons between reservoir characteristics determined by routine petrophysical analysis and predictions using the GDM for three separate blind tests.

As with any model driven analysis, the answers are only as good as the input data. Due to uncertainty over how to petrophysically obtain the desired outputs for the shale model wells, work on the shales was halted early in the program. Subsequently, testing has successfully shown that we were able to relatively quickly (within 2-3 weeks) develop a predictive model, which could, within reason, predict basic reservoir characteristics for tight gas sands from routine drilling parameters, mud gas and lithology data. While further input data preparation is required, initial results provided significant encouragement and highlighted the potential of this technique for both real-time and post-drilling analysis.
Application of Integrated PTA and PDA Approach in a Tight Gas Reservoir in China
Authors: Tongyi Zhang , Wei Pang , Juan Du , Jun Mao , Ying He , Qiong Wu , Xiaoxu Feng , Panglu Jiang , Dejia Di
Published: June 2014

It is quite common for production/injection wells to install permanent or temporary downhole pressure gauges. When the well is shut in, the pressure gauge will record the falloff/buildup (BU) transient data lasting from hours to several days with high frequency. The pressure transient analysis (PTA) can be carried out using the recorded data. When the well is producing, surface pressure and rate will be recorded daily or monthly based on which production data analysis (PDA) can be performed. For a fractured tight gas well, we may get accurate permeability from PTA if a radial flow is reached; however, seldom is the case that we can obtain boundary information from PTA because the permeability is too low. On the contrary, we may easily get boundary and volume from PDA if the well is producing long enough, but sometimes it's hard to get permeability estimation. If we can integrate PTA and PDA together, we may get both permeability and boundary, and increase the interpretation's confidence by letting PTA and PDA result consistent with each other.

This study illustrates one fractured vertical well in a typical tight gas reservoir in China. The well contained one pre-fracture buildup test and annual pressure buildup tests in 6 subsequent years. From the pre-fracture buildup test, we get the accurate permeability with value of 0.086md; the annual buildup tests showed continuous changes in the fracture morphology with fracture conductivity decreasing from 3000 to 300 md.ft and fracture half-length increasing from 226m to 322m.

Such successive Buildups recordings are rare and the observed changes in fracture conductivity and length over time were unanticipated. It reveals that variation of fracture half-length and conductivity may be a typical factor we should consider in pressure transient analysis. The PDA shows the difficulties in determining formation and fracture parameters when the transient response lacks radial flow.
Water Dumping Improved Recovery for Bounded Thin Oil Reservoir of East China Offshore
Authors: Zhang Guohua , Li Yangfan , Xu Fa , Jia Jianyi
Published: June 2014

Bounded thin oil reservoir, which is characterized by less reserves, thin thickness, and weak energy of edge or bottom water, could hardly be developed with high cost, low recovery and high risk. Bajiaoting oil field, which is located in East China Offshore, has all the characteristics of bounded thin oil reservoir, what's more, it has low permeability: less than 10mD. As a result, it could not be developed without water injection wells, but water injection cases could not be taken in East China Offshore due to the restrictions of the producing platform. Face all the difficulties, Water Dumping, which could maintain pressure and improve recovery with low cost, was applied in Bajiaoting oil field, and it is the first time that this technology applied in China offshore. Traditionally, water injection wells are located in the edge of the reservoirs and oil wells are located in the centre area. By contrary, new case was put forward: transform the oil well which located in the center into water dumping well in the appropriate time. Therefore, dumping water could spread from edge to the center, and then, to the other edge. In this study, related calculation methods for pressure and injection rate are applied, and the effects and simulation results of some adjustment cases are discussed.
Improved Underbalanced Operations with Uncertainty Analysis
Authors: Udegbunam John Emeka , Lohne Hans Petter , Fjelde Kjell Kåre , Arild Øystein , Ford Eric
Published: June 2014

Underbalanced operations (UBO) involve handling of a highly dynamic system. Therefore, the use of flow models in the well planning, training, and subsequent operations is indispensable. These model predictions, however, are subject to uncertainties, due to input errors or imperfect modeling algorithms or both.

In the preceding work, the effects of uncertainties related to gas-slip parameters and frictional pressure loss on annular pressure during underbalanced drilling have been discussed. The work demonstrates the advantages the proposed stochastic flow model has over the deterministic formulations currently used in the industry.

The present work specifically focuses on how to include uncertainties associated with reservoir inflow performance and choke operability. Monte Carlo simulation is used as a means to propagate these uncertainties. Because reservoir influx is expected during UBO, understanding the impact this will have on annular pressure will be very beneficial when selecting the optimal operational conditions.

The stochastic modeling of UBO has demonstrated its potential as a future tool for managing the associated risks and uncertainties. Improving the planning process with the uncertainty approach can make the application of the drilling technique more attractive to oil and gas operators.
Filtration in Frac-Packs and its Impact on Injector Performance
Authors: Hwang Jongsoo , Lehardi Samuel , Sharma Mukul M.
Published: June 2014

The filtration of solids in the injection water in a frac-pack is the primary factor which controls the injectivity decline in frac-packed water injection well completions. The injectivity may decline rapidly or much more slowly depending on the degree of frac-pack filtration. The widening and lengthening of frac-packs and the associated loss of sand control are affected as well. However, there is no experimental data for the filtration coefficient in high velocity flows in frac-packs. In this research, the filtration coefficients were experimentally measured in high velocity flows encountered in frac-packs. The solid concentrations and pressure drops across proppant pack sections were measured to properly utilize filtration theory and permeability decline models. The filtration coefficients were measured at various flow rates and for different proppant sizes. Our experiments show that at high fluid velocities, the filtration coefficient is significantly lower than that estimated from prior correlations that are based on low velocity filtration.

Our experimental results were used to obtain new empirical correlations for filtration coefficients at high flow rates in frac-packs. The experimental coefficients were used as the primary input into a well injectivity model. The proper estimation on the filtration enabled us to analyze the impact of injection rates and proppant selection on injector performance, i.e., predict longterm injection well behavior. The effect of particle filtration in the frac-pack and its effect on injector performance was captured accurately for the first time. The empirical correlations together with a model for frac-pack growth in the injection well allowed us to accurately estimate fracture dimensions and the long-term water injectivity of frac-packed injectors. These results can be used for frac-pack design, proppant selection and specification of injection water quality.