bluuebunny/crossref_metadata_2025 huggingface dataset:
Production-Data and Pressure-Transient Analysis of Horseshoe Canyon Coalbed-Methane Wells, Part II: Accounting for Dynamic Skin
Authors: Clarkson Christopher R. , Behmanesh Hamid , Chorney Lance
Published: June 2014

In a previous study (Clarkson 2009), advanced production-analysis techniques, including production type curves and flowing material balance (FMB), were applied to Horseshoe Canyon (HSC) coal wells to establish the applicability of these techniques and to resolve the importance of multilayer behaviour for production analysis. The field examples chosen for analysis included single wells that exhibited production declines analogous to shallow gas wells, with decline in production occurring from day 1, and in one case exhibiting transient-flow characteristics. There are many more HSC wells that exhibit less-straightforward production characteristics, including flat or even inclining production. These wells have production profiles qualitatively similar to two-phase coalbed-methane (CBM) wells, yet lack water production. There are several possible explanations for the flat or inclining production behaviour, including changing skin associated with near-wellbore cleanup of drilling fluids over time, and increase in absolute permeability associated with matrix shrinkage. Regardless of the cause, these effects need to be accounted for in quantitative production analysis. In this follow-up paper, we continue to perform comparisons between multilayer and single-layer-equivalent production analysis of HSC wells, but focus on wells that exhibit inclining gas production. We develop a methodology to correct for changing skin in both type-curve and FMB analyses that allows this more-complex well behaviour to be analyzed. We validate the new methodology using a simulated example, and then apply it to actual field cases. Changing skin and absolute permeability by layer/coal zone was quantified through periodic shut-in/buildup testing of isolated coals throughout the life of the wells, and these dynamic properties were used in production-data analysis and analytical simulation. Comparing single-layer-equivalent and multilayer analysis, we have found differences in estimated-ultimate-recovery (EUR) values of less than 15% because the existence of one or two dominant (high-kh) coal zones. Additionally, we investigated the impact of free-gas storage on the results of productiondata analysis of HSC wells. The production-analysis methodology introduced in this work, while useful for analyzing HSC coal wells with dynamic skin/permeability, is expected to be applicable to a broader range of reservoir types that exhibit this complex behaviour.
Optimizing the ROI of Digital Technologies in Production Operations
Authors: Prakash Amit , Bansal Aashish
Published: June 2014

Digital Oil field technologies continue to gain ground and lead the march of the oil and gas industry into deeper and more difficult sites for exploration and production. Most of the companies have adopted these technologies, but many have failed to realize their full value due to various reasons, the most common of them being the absence of a process framework to adopt such technologies on a firmwide/ business unit level. As a consequence, companies continue to move into the digital age at a snail's pace largely due to isolated efforts of adopting these technologies by different groups and no firm-wide embedment. This paper recommends a well defined framework to enable the adoption of these technologies at all points of the business process. The framework spreads across the production operations part of the value chain and will enable companies to adopt technologies seamlessly at a faster pace realizing maximum benefits at optimal costs.
Partial-SAGD Applications in the Jackfish SAGD Project
Authors: Li Pingke , Stroich Al , Vink Andrew , Nespor Kristian , Bhadauria Swapnil , McCormack Mike
Published: June 2014

With steam-assisted-gravity-drainage (SAGD) operations, there will be times that the producer downhole temperature falls below the desired level. This situation may occur when a shut-in is required because of facility or well operational issues. Cooling bitumen and steam condensate, which continue to drain and raise the liquid level over the producer, cause difficulties with the restart. The producer could also cool if the well pair is converted prematurely from circulation to full SAGD mode.

A variety of artificial-lift technologies have been applied in field applications. However, with its dual-tubing-completion design and gas lift system, Devon has successfully used partial SAGD methods to optimize restart strategies and effectively deal with times when the producer unexpectedly cools.

This paper describes three SAGD operating modes used by Devon at Jackfish: full SAGD, semi-SAGD, and partial SAGD. During partial SAGD, the fluid return from the injector stops while steam injection continues down either the long tubing (LT), short tubing (ST), or the annulus. The producer continues to be circulated with the appropriate steam-injection rate into the LT and fluid returns up the ST. Numerical-simulation results associated with partial SAGD are presented. Partial-SAGD applications at the Jackfish SAGD project are discussed.
Oilfield Data Mining Workflows for Robust Reservoir Characterization
Authors: Holdaway Keith R.
Published: June 2014

"There are more things in heaven and earth, Horatio, than are thought of in your philosophy" "Hamlet" William Shakespeare

To fully appreciate the plethora of disparate data sets across the upstream geoscientific silos, it is essential to establish a sound and consistent suite of workflows that embrace data management facets as well as diverse data mining modules established under the banner of soft computing or artificial intelligence. When does one implement a neural network, a decision tree or non-linear regression techniques? Will Genetic Algorithms or Fuzzy Logic be appropriate for my objective function?

This paper sets out to answer some important questions around data mining workflows underpinned by exploratory data analysis, confirmatory data analysis, descriptive and predictive modeling to establish sound and important reservoir characterization decision-cycles. Case studies are presented to illustrate effective and successful studies based on advanced statistical analysis and AI workflows in sandstone and carbonate reservoirs. Can such workflows be adopted in unconventional reservoirs? Determining accurate and effective hydraulic fracturing packages are keys in tight gas plays, and this paper explicates how data mining workflows can be successfully applied in such unconventional plays.
Sophisticated Software Analysis System and Use of Torque/Drag Modeling for Complex Well Operations Increases Operational Efficiency
Authors: Xie Liangjun , Moran David , Yan Lei , Mercado Jose , Bits Smith
Published: June 2014

Accurate torque and drag (T&D) analysis is a fundamental well planning tool essential for predicting and preventing drilling and completion problems. To guarantee an efficient and safe operation, tension/compression and torque on the bottom hole assembly needs to be controlled within acceptable limits. Practically all available torque and drag software can calculate the following general operation modes: rotating off-bottom, pick-up, slack-off, rotary drilling and oriented drilling modes. However in the well construction process, there are many other complex operational modes that are largely absent from available software systems, as discussed in the literature. The industry requires modeling methodology to analyze complex well operations including: setting and un-setting packers, anchoring liner hangers, shearing pins in wellbore departure operations, loading and operating drilling/fishing jars in both overpull and compression.

The authors will discuss new modeling software capable of analyzing complex well operations including liner hanger and jarring operations in detail. Further discourse about how modeling these special operations were combined with field experience and confirmed the accuracy of the new module with regards to both special operations and conventional T&D capabilities. The simulation/analysis recommendations were successfully executed in the field and led to increased operational efficiency and unplanned cost avoidance. Case studies will be presented of successful liner hanger deployment and complex drilling jar simulation.
Smart Metering: An Online Application of Data Validation and Reconciliation Approach
Authors: Haouche M. , Tessier A. , Deffous Y. , Authier J-F. , Couput J-P , Caulier R. , Vrielynck B.
Published: June 2014

The availability of reliable data is obviously a prerequisite to good production optimization. So far, many tools have been developed to increase the availability of data by using Smart Completions, Downhole Measurements and Remote control Sensors installed along the production chain. The progress in production models has also contributed to this improvement. Nevertheless, in term of reliability, the collected data are affected by uncertainties, which must be taken into account.

The process of Data Validation and Reconciliation (DVR) considers all the relevant information (measures/ models) of the production plant as one integral set of parameters. Furthermore, the originality of DVR as compared to equivalent systems is the use of a statistical model to control uncertainties associated with each parameter, and calculating the resulting error propagation. As results and thanks to the information redundancy, DVR allows an automatic real-time correction of each parameter based on its allocated uncertainty.

In this paper, we focused on a real time application with 16 Wells belonging to 3 offshore Platforms. The single-Well model is initially validated by using the Multiphase Flow Meter (MPFM) measurements.

The global results analysis is discussed by comparing the online application outputs with production tests using MPFM, in terms of Oil flow-rate and Water Liquid Ratio (WLR). Also, the monitoring of each information is highlighted in order to detect a model deviation or instruments failure. Furthermore, the error distribution is used to identify the impact of any deviation occurring in the application.

Conclusions are drawn on the performance of the virtual metering system in terms of online availability, results reliability and global consistency between data and results. The DVR application is considered as an operational monitoring tool thanks to alarms which are customized by operators, and as an analysis tool for investigation and diagnosis studies.
Improving Oil & Gas Installation Safety through Visualization of Risk Factors
Authors: Braseth A. O. , Sarshar S.
Published: June 2014

This paper presents the second version of the Maintenance and Modification Planner (IO-MAP). IO-MAP is a software tool designed to reduce risk in job planning on offshore oil & gas installations in an Integrated Operations (IO) setting. In this situation the planner is likely to have reduced knowledge of the actual installation, and the intention of the IO-MAP is to support the operator in safe job planning through visualization of risks on the actual installation. Risks such as hot work, potentially falling objects, workload and weather data are visualized. The new version is intended to support multiple users planning offshore jobs on a shared large projected display. It is an evolutionary design, based on feedback from exploratory studies on the first version. The studies on the first version identified several improvement areas were parts of the design was too complex and abstract. The new version of the tool described in this paper, has redesigned several objects to be more intuitive and less abstract. The colour scheme has improved consistency for easier comparison of risk factors on the installation. New functionality related to risk factors is also included. The graphical design scheme is inspired from Information Rich Design used in other applications such as large screen displays for oil & gas process monitoring in Norway.
Energy Company Perspective on Virtual Worlds / 3-D Immersive Environments
Authors: Morneau Richard A. , Van Herreweghe Williams G. , Little Joe W. , Lefebvre Dominique B.
Published: June 2014

Many industries, including the Energy Industry, are leveraging virtual world based technologies to enhance training and situational understanding. The phrase "a picture is worth 1000 words" is implicitly understood because "seeing" helps crystallize concepts making more transparent the ambiguity of the spoken word.

Virtual Worlds are 3-D immersive environments, which allow workers to perform tasks and collaborate within a virtual representation of their normal work environment. Virtual world technologies represent a step forward in understanding work process complexities within a collaborative environment providing workers with the ability to be active participants, through their avatars, within a virtual representation of the world in which they work.

Achieving operational excellence requires a broad, holistic view of all operational aspects. Current state-of-the-art methodology calls for assembling various data feeds into complex dashboards, which may not bring clarity to operational situations. And, dashboards do little to help one understand the implications associated with various work processes behind the data feeds. While dashboards are a step in the right direction and are certainly better than having to find the information in different isolated systems they still fall short in providing operational awareness for complex multifaceted work processes. This is especially true in our facilities, which are large complex environments. New facilities and major capital projects present their own opportunities. Our challenges are further complicated by our multinational workforce, which does not have a single common first language. Work done at Harvard University has found that virtual world technologies offer advantages in these circumstances for learning.

Operational excellence is brought about by operational awareness. Operational awareness is brought about by seeing and interacting with the data within its proper context. This paper will present how virtual reality based technologies can reduce ambiguity and enable contextual operational awareness which helps achieve operational excellence, illustrating that seeing and doing within the work process context increases understanding. The digital oilfield and digital plant can be intelligently exposed with virtual reality technologies.
Integrated Environmental Monitoring in Daily Operations
Authors: Hepsø Vidar , Låte Mona , Gramvik Geir , Johnsen Ståle , Nilssen Ingunn , Wesenberg Harald
Published: June 2014

The term Integrated Environmental Monitoring (IEM) refers to the tight coupling of sensor based real-time environmental monitoring with day-to-day operations. In that perspective IEM extends the traditional meaning of the term environmental monitoring by including discharge control, leak detection and remote sensing. Using offshore operations as an example, environmental monitoring has often been perceived to mean off-line sampling of seabed sediments and the water column during annual and triennial campaigns by ship. Whereas such monitoring has its place in a total monitoring programme, advances in technology and methodology open up for more flexible and real-time sensor based monitoring which can be tied closely to daily operations in the oil and gas industry. A multidisciplinary approach is sought to address these challenges, where input is needed from diverse domains as marine biology, subsea field development, sensor instrumentation and organization development. IEM relies on the presence of several technical and organizational capabilities. Some of these are similar to what has been developed in other areas of the oil & gas industry, for example through increased use of real-time data in drilling and well operations or in the cross-discipline collaboration variously labelled Integrated Operations, e-Field or Digital Oilfield. IEM applies this experience to the environmental monitoring domain. Statoil is currently developing an architecture or a new capability platform to take advantage of these opportunities. This platform has the following layers: intelligent infrastructure, information and collaboration, knowledge sharing & analytics and finally business operations. The paper presents how Statoil sees environmental monitoring over the life-cycle of a field and the overall architecture/platform for Integrated Environmental Monitoring (IEM) will be presented together with some of the focused development areas.
Pre-Salt Production Surveillance – The First Journey Across Processes in Santos Basin
Authors: D'Andrea T. Z. , Sanomya T. , Lima C. B. , Bastos M. D.
Published: June 2014

An Integrated Operations initiative is on going at Santos Basin in order to face the new challenges of Pre-Salt greenfields. This initiative is being conducted at Petrobras through a corporative plan called GIOp (Integrated Operations Management) and, to potentialize lessons learnt, the company is deploying a pilot in Santos (city located at São Paulo State – Brazil).

Petrobras has already tried to apply the smart field concept in previous experiences. The company selected the 20 most interesting processes to be redesigned following the IO concept to run a Pilot in Santos Basin, aiming to test this concept, exercise the collaborative way of working, and acquire experience. This phase used some key available features as tools, temporary collaborative environments and resident professionals. The focus was to obtain early results with a quick wins strategy. Therefore, well and process plant surveillances were implemented for all units of the Santos Basin, followed by a 24/7 Operational Support, which is directly connected to the production units and offshore operations.

This paper describes the implementation and execution of the production surveillance activities in Santos Basin, pointing to practical cases of application, across related processes. Many improvement opportunities have been exercised in several disciplines and production assets, in order to incorporate the lessons learnt to the process mapping and bring valuable information for the following phases of the GIOp implementation in Brazil.
ISIS Rate & Phase: Delivering Virtual Flow Metering for 300 Wells in 20 Fields
Authors: Heddle Richard , Foot John , Rees Hugh
Published: June 2014

At the SPE conference in 2006 BP announced the Field of the Future Integrated Surveillance Information System (ISIS) project. Since then the ISIS system has been developed, delivered, tested and verified. Deployment to BP assets has been at the scale and pace proposed in the conference papers published at that time. This paper describes a core module, the Rate&Phase virtual flow meter, and also gives reasons why deployment has been achieved so successfully.

BP's Rate&Phase system automatically estimates production rates from individual wells and other well performance and reservoir information at least once per hour. The approach has been to automate a proven Petroleum Engineering methodology using models of well hydraulics and flow though chokes. The system takes advantage of the instrumentation typically installed on new wells and the transmission of those data for analysis at technical centres often remote from the production sites. Rate&Phase is integrated in ISIS along with routines to automatically reconcile production across entire fields, monitor issues of erosion and sand production and estimate reservoir pressure at shut-ins.

The Rate&Phase system has been deployed widely across BP-operated assets including many major oil and gas fields. Benefits have been realised from the ability to efficiently monitor well stock, manage fields better and allocate production more accurately. The effort to determine monthly production allocation is significantly reduced. Production gains have been realised through assets operating closer to constraints because of the assurance of flow rates in critical pipework. Developments are being introduced to reduce maintenance effort through tools to assist model re-calibration and to complement the hydraulic models with models derived entirely from measured data.

Rate&Phase exploits commonly-used modelling tools and is designed to be easy to deploy/configure. Acceptance of the system has been hastened because it is not regarded as a black box and all results can be reproduced manually offline. Current production and performance information is readily available and changes over time can be trended though existing data interfaces.
Continuous Monitoring of Thermal EOR at Schoonebeek for Intelligent Reservoir Management
Authors: Hornman J. C. , van Popta J. , Didraga C. , Dijkerman H.
Published: June 2014

Time-lapse seismic has shown many successful offshore applications, but has turned out to be much more cumbersome when applied onshore. Successful applications are mainly observed for shallow objectives and large acoustic impedance changes, such as thermal EOR and CO2 injection. The dominant problems for onshore time-lapse are caused by near-surface variations between base and monitor surveys [Pevzner 2011]. By taking appropriate measures in acquisition and processing it is possible to overcome these problems. We demonstrate that with a continuous seismic time-lapse field trial in Schoonebeek, The Netherlands, where thermal EOR is applied. The time-lapse measurements not only enable us to observe pressure and temperature variations in the reservoir, but also to quantify these variations. These measurements complement the measurements made in wells, enabling the reservoir engineer to construct more accurate dynamic models, which make it possible to make better reservoir management decisions. We will describe the steps taken in acquisition and processing of the data and show an interpretation of the measurements.
The Time Has Come For Truly Integrated Workflows: A Different Approach To Cross Functional CWE's
Authors: Crockett Brian , Busaidi Khamis
Published: June 2014

Description

Collaborative Work Environments, in the past, have tended to concentrate on optimising single issues in real time. This paper looks at combining subsurface and surface activities in one integrated solution and proposes that the way forward is to provide a workflow that will combine multiple skills and capabilities in order to make information available sooner so that decisions can be made faster which will resulting in better performance for the asset.

Application

To demonstrate how the normally independent subsurface and surface functions can be combined in an integrated set of business processes which cuts across functional silos and capitalise on: Shared real-time dataExpert knowledge of wells and reservoirsLean approach to Production and Maintenance

To use a cross-domain workflow which combines people, processes and technology in a way that permits problem solving and production system optimisation opportunity generation.

To provide a case study which serves to revitalise the goals of the Collaborative Work Environment (CWE).

Results

The approach was tested across two clusters with over 2000 wells, different functions and reporting structures, which resulted in: Less time taken to restore wells to productionIncreased number of wells operating within their operating envelopReduced time taken by Production Technologists to gather data for well reviews

Observations

The following changes in patterns of behavior were observed: Cooperation between functions to integrate the 90 day production plan with well activities took placeA coordinated approach between surface and subsurface to make available materials, rigs and hoists for interventions resulted in improved working relationshipsThe direct relationship between process steps, tools and applications provided lean standard operating procedures

Conclusions

The conclusions can be summarized under the following headings: Integrated Business ProcessesStandard processes need to integrate with all the others to optimiseLean Business Organisation•Requires the identification of roles and responsibilities•Needs to employ new ways of working in order to remove functional barriersAppropriate Digital TechnologiesNeeds to be real-time exception based monitoring toolsOptimised Audio-Visual FacilitiesDemands clearly identified collaboration events

Significance of Subject Matter

This approach and case study identifies how clear corporate vision can be adopted on a large scale to implement standards and guidelines using a global model to drive transformation.
Real-Time Advanced Warning of Screenouts With the Inverse Slope Method
Authors: Massaras Leon V. , Massaras Dimitri V.
Published: June 2014

Unconventional plays require multiple hydraulic fracture treatments placed in vertical or horizontal wellbores in order to be economical. These are very complex operations performed on-location in an orchestrated manner by many contributors. A screenout puts many of the contributors on stand-by status, delays the placement of subsequent stages, and, results in cost overruns due to stand-by charges, wellbore cleanout operations, and, lost production days. Thus, advanced warning of screenouts is a major technical advance in hydraulic fracturing.

Advanced warning of screenouts in real-time is a great advantage due to the ability to exercise decision control for early termination of the treatment, or extension of the treatment.

A screenout is imminent if the surface pressure slope deviates from the inverse slope (positive surface pressure slope). This allows for early initiation of the displacement (flush) procedure, and prevents leaving in the wellbore excess proppant. When only the designed amount of proppant is left in the wellbore high net-pressure develops, along with adequate packing of the near-wellbore area and a much wider fracture.

A treatment can be extended if the surface pressure slope doesn’t deviate from the inverse slope (positive surface pressure slope). Thus, if extra fluid and proppant are available on location the treatment can be extended. This would result in a much better placement of the proppant pack, as it would result in a higher net-pressure, a wider fracture, and higher production rates.
Managing Operation Events in Real-time: From Smart to Smarter
Authors: Khan Furqan , Testard Benjamin , Boero-Rollo Jean-Gregoire , Verbrugge Eric
Published: June 2014

Building an instantaneous image of field performance from continuous observation and analysis of real-time data is the essence of so-called ‘intelligent’ or 'smart’ operations. However, visualization of trends alone has limited value in detecting and analyzing anomalies arising in complex production systems. Identification and classification of ‘operational events’ is far more powerful to capture real-life experience required to optimize performance. This paper presents an Events Management System developed to support automated anomaly detection and analysis.

The Events Management System is part of an integrated real-time surveillance platform and can be configured to support a wide range of applications. The system was successfully deployed to record running conditions of rotating equipment. A more complex application was developed to analyze efficiency of preservation procedures used to operate subsea networks outside hydrate conditions during shutdowns. In each case, the system successfully recognized event sequences and automatically computed valuable information such as maintenance statistics, cool-down times or injected methanol volumes, a cumbersome exercise seldom performed manually.

The proposed examples illustrate how events management can significantly enhance the value of real-time monitoring systems. An immediate benefit is to simplify compilation of complex performance indicators and time consuming corporate reports. A more important aspect is the ability to adapt operational procedures according to historical performance. In longer term, building a structured and reliable real-life experience repository is essential to feed continuous improvement processes.

Adequate expertise is almost always available as back-office support if not at site; what is generally lacking is efficient processing of the growing amount of real-time data and synthesizing them into manageable pieces of meaningful information. Events Management Systems are still in their infancy. With increasing number of digitally-enabled production sites, such systems are expected to gain more importance in near future.
Buckling of Tubing inside Casing
Authors: Mitchell Robert F.
Published: June 2014

Oil wells typically have multiple concentric casing strings. For a set of two concentric strings, if the inner pipe has a compressive axial force, it will typically buckle within the outer string. The buckling of pipe can be important in the analysis of a well-completion design, as the buckled pipe can develop bending stresses that may be significant. Most analyses of this problem assume that the outer casing is rigid. In reality, this external casing is also elastic and would displace owing to the loads generated by contact with the inner pipe. Further, if both strings have compressive axial forces, both strings will buckle, and the resulting buckled configuration must fit together so that contact forces between the two strings are positive and the pipes do not each occupy the same space. If the two strings have an external, cylindrical rigid wellbore, then any contact forces with this wellbore must also be positive, and the buckled pipe system must lie within this wellbore.

There is only one known solution to the multiple concentric pipe-buckling problem, that of Christman (Christman, 1976), who proposed a composite pipe based on the summed properties of the individual pipes. This analysis does not conform to the requirements posed in the previous paragraph.

This paper presents the various ways that two concentric pipes can interact when one or both pipes are in compression and would then have a tendency to buckle. The contact forces between the pipes and with the external wellbore are explicitly calculated, and contact or non-contact conditions are determined. All results are analytic so that they can easily be used in spreadsheets or hand calculations. Several example calculations are presented to illustrate how these results might be used.
Determination of Biot's Effective-Stress Coefficient for Permeability of Nikanassin Sandstone
Authors: Qiao L.P. , Wong R.C.K. , Aguilera R. , Kantzas A.
Published: June 2014

In Alberta and British Columbia, a huge amount of tight gas is trapped inrelatively low-permeability rock formations. Physical fracturing of theseformations could enhance the overall formation permeability and thus improvetight gas extraction. One of the outstanding issues in rock fracturing is todetermine the magnitude of applied effective stress. The generaleffective-stress law is defined as seff =sc - asp, where sc andsp are total confining stress and fluid pore pressure,respectively. Each physical quantity of rock responds to total stress and porepressure in a different way, and thus each quantity has its own unique Biot'seffective-stress coefficient. The main objective of this study is toexperimentally determine the Biot's coefficient for permeability of Nikanassinsandstone. A series of permeability measurements was conducted on Nikanassinsandstone core samples from the Lick Creek region in British Columbia undervarious combinations of confining stress and pore pressure. In addition,permeability values were measured both along and across bedding planes toinvestigate any anisotropy in the Biot's coefficient.
Detrimental Effect of Temperature on Fines Migration in Sandstone Formations
Authors: Musharova D. A. , Mohamed I. M. , Nasr-El-Din H. A.
Published: June 2014

The present work investigates the impact of high temperature on fines migration and is useful for both sandstone and shale formations at high temperatures. The results show subsequent loss of permeability in clay-containing rocks such as sandstone. Three types of clays are present in sandstone rock used for experiments: kaolinite, illite, and chlorite. Both experimental and theoretical results of conducted coreflood experiments show that the rise in temperature sensitizes fines, and thus decreases sandstone permeability significantly upon the injection of fresh water.

Coreflood experiments were performed at 74, 200, and 300°F temperatures. Brine, 5 wt% NaCl was injected at room temperature to determine the initial rock permeability. Next, temperature was applied to the system, and various potential clay stabilizing salts, as well as fresh water flooding, was performed in both forward and reverse directions to confirm plugging. Core effluent was collected during each experiment and analyzed to measure the concentration of key cations using ICP-OES.

The experimental results were verified by application of the DLVO theory. The mathematical model was used to evaluate the magnitude and determine the effect of each of the contributing forces. The results show that the double layer repulsion force has the most significant impact, due to change in temperature of the matrix-clay system.

Based on the results attained, it can be concluded that fines migration is a serious problem in sandstone formations at high temperatures. High salt concentrations or salts containing high valency cations will be required to mitigate fines migration due to pH changes at higher temperatures. From experimental results obtained, 15 wt% NaCl and 15 wt% HCl solutions were able to preserve permeability in the rock and minimize fines migration at elevated temperatures. This paper will discuss experimental and theoretical studies conducted that highlight the importance of fines migration in hightemperature wells.
Using Enhanced Fracturing-Fluid Cleanup and Conductivity in the Hosston/Travis Peak Formation for Improved Production
Authors: Modeland N. , Tomova I. , Loveless D. , Holtsclaw J. , Yeager V.
Published: June 2014

For many years, the Travis Peak/Hosston formation of East Texas and North Louisiana has been hydraulically fractured with various treatment designs, ranging from low-viscosity water fracs using only linear gel or polyacrylamide friction reducers to crosslinked gels typically sourced from guar polymers or guar derivatives. While lower-viscosity fluids can minimize gel damage to the formation, the result is often that less fracture conductivity is achieved because of the inability to transport larger proppant concentrations and maintain width. In late 2010, a new milestone occurred for the East Texas/North Louisiana region as a newly developed crosslinked gel system, souced entirely from the food industry, was incorporated into the Travis Peak/Hosston fracture designs. The fluid system demonstrates both better proppant-transport capabilities and better conductivity-performance numbers than friction-reducer polyacrylamide systems and typical guar fluids. In addition to enhanced cleanup and proppant transport, all of the fluid system’s components, having been sourced from the food industry, demonstrate a health, safety, and environmental (HSE) quality that surpasses the previously used fluid systems. This paper will show laboratory test results for retained conductivity and proppant transport for the sourced-from-the-food-industry (SFI) fluid system in comparison to other fracturing gels, both of which should aid in flowback and production of a tight-gas sandstone formation.

Case histories for the Landon No. 6 well (a single-stage Travis Peak and Pettet completion in Rusk County, Texas) and the Shadowen 3-2 well (a four-stage Hosston completion of DeSoto Parish, Louisianna) will be examined. These two wells were the early pioneers for this SFI fluid system and have both shown benefits from its improved fluid cleanup and conductivity capabilities. Nearby offset comparisons of the production well show these wells to outperform wells with similarly completed frac stages using different fluid systems. Use of this SFI fluid in the tight-gas sandstones of East Texas and North Louisiana not only exemplifies the environmental stewardship of the oil-and-gas industry, but can also lead to improved estimated ultimate recovery (EUR) of the wells.
Successful Optimization Strategies Combine to Deliver Significant Performance Boost at the Edge of the ERD Envelope, Sakhalin Island, Russia
Authors: James Richard W. , Pastusek Paul , Kuhn Gary R. , Andreev Anton , Bailey Jeffrey R. , Wang Lei
Published: June 2014

Numerous performance enhancement initiatives were used by the operator for the Sakhalin I project in drilling and completing the world-class extended reach drilling (ERD) program at the Odoptu Field, Sakhalin Island, Russia. As a result of the drilling successes and favorable production performance, the initial seven-well ERD program was expanded to nine wells, including the world record OP-11 well. The operator’s philosophy of relentless redesign to remove limiters from the drilling process resulted in significant performance improvements in all areas of drilling and completion operations. This paper provides details and results for many of the key performance initiatives used.

Operators are continually striving to drill longer, faster, and at lower costs while minimizing risks to provide maximum shareholder value. During the Odoptu ERD drilling program, a constant progression of performance improvement, time reduction, and dependability strategies were used. These optimization initiatives resulted in significant performance improvements for the project and numerous industry records.

The nine Odoptu ERD wells were drilled at a cost below the budgeted amount for the first seven wells. As a result of the initiatives employed, non-productive time (NPT) was reduced from an average of 21% on the first four wells to less than 3% on the last five. Aggressive shock and vibration mitigation efforts through bit redesign, bottomhole assembly (BHA) vibration analysis and operational optimizations resulted in record BHA runs. Wellbore instability issues were successfully mitigated through design and operational practices. Completion practices were high-graded and optimized and as a result, all completions in the long horizontal intervals were successfully placed using partial string rotation techniques.

Drilling ERD wells at the edge of industry experience in a cost effective and low-risk manner requires careful attention to detail and a commitment by the operator and contractors to continuously improve.
Results of Jan. 25, 2011 IADC Shale Drilling Technology & Challanges Workshop
Authors: Torkay D. , Brakel J. , VanMarel H. , Geehan T. , Shelton A. , Reid D. , Killalea M. , Womer K.
Published: June 2014

This paper presents the results from a workshop on Shale Drilling Technologies and Challenges held in Houston on January 25th, 2011. This workshop, sponsored by the IADC Advanced Rig Technology, Future Technology Subcommittee, brought technology leaders and engineers together to discuss issues related to North America Shale Drilling. Led by specialists with operating, contracting and technology companies, the workshop goal was to educate the industry regarding existing technologies and challenges. A unique aspect of this workshop featured results of sociology studies on the onshore O&G industry and the perceived challenges of drilling in urban environments. This is the second of a series of planned workshops to address technology needs which were identified in an industry survey conducted by the IADC ART committee in 2009 and reported in SPE 128953.
Improving Well Productivity/Injectivity on Deepwater Offshore Horizontal Drains
Authors: Menezes C. , Benchimol L. , Mcewan M. , Ohwo A. , Poinset V. , Sutherland G.
Published: June 2014

Near-wellbore formation damage and high mechanical skin is a concern on the deep water horizontal wells drilled and completed off the West Coast of Africa. Due to the typically unconsolidated sandstone reservoirs, sand control is essential, either Stand Alone Screens (SAS), or Open Hole Gravel Pack (OHGP) sandface completions are run to contain the sands. Although the drilling mud is replaced by sieved mud, and carefully controlled for solids, plugging can still occur through insufficient degradation of the filter cake. In addition, losses during the drilling of the drain and even the screen size vs. open-hole diameter can also have a significant impact.

Productivity impairment issues originally encountered on Rosa producer wells (Deep offshore Angola, Block 17) led to the development and testing of a unique micro-emulsion technology in 2006, for use with coiled tubing deployed remedial treatment inside the screens. The ‘cake breaker’ system, a stable blend of surfactant, acid and brine, was tailored for the mud system used, and designed for fast acting remedial treatment. The results of the Rosa intervention treatments proved successful and additional testing was carried out in 2007 / 2008 to benchmark the tailored system to other products on the market. The tailored system remained the system of choice and the same remedial treatment formulation was applied on some of the earlier Dalia wells (producer & injector). Treatment results were positive, and have improved further still by optimizing the formulation.

Preventative treatments have also been developed, using various deployment methods. The evolution has been towards a displacement of the mud in the open hole / screen annulus, prior to displacing inside the screens. The results have been mixed however, with the remedial treatments generally proving more effective than the preventative treatments. This paper looks at the experience gained on the deep water horizontal wells in Block 17 off the west coast of Angola, namely the Rosa, Girasol, Dalia and more recently the Pazflor field. The differences in results are evaluated and the various methods and lessons learnt are presented.
Foaming Aqueous-Based Curable Treatment Fluids Enhances Placement and Consolidation Performance
Authors: Nguyen P. D. , Rickman R. D.
Published: June 2014

Conventional solvent-based resins (SBRs) have often been used to resolve solids-production problems in producing wells by coating the particulates, such as formation sand, fines, and proppant, with a curable resin to hold the grains together without reducing the treated pack’s permeability. However, the SBRs have low flashpoints that can present safety issues during storage, handling, and well-completion operations. These resin systems have been typically applied in short intervals of less than 30 ft and have had limited success in longer intervals. With the recent development and applications of aqueous-based resins (ABRs), these drawbacks have been overcome. Because solvent-based chemicals are replaced with aqueous brines as carriers in treatment fluids, ABRs have high flashpoints, similar to those of water. Additionally, because ABRs are aqueousbased fluids, they can be foamed so that the operator may simply bullhead the fluid directly into the wellbore to treat long intervals without requiring a rig or zone isolation packers.

This paper presents the results of laboratory experiments aimed at understanding and quantifying the performance of ABR treatment fluids in consolidating weakly or unconsolidated formation sands or loose proppant packs. Consolidation strengths and scanning electron micrographs of the treated formation sand or proppant packs were analyzed to identify the mechanisms behind the treatment fluids in providing cohesion between particulates and how the pore channels within a pack matrix remain open, minimizing permeability loss. Both foamed and nonfoamed ABRs were determined to provide effective consolidation levels to the treated formation sandpacks, regardless of whether foamed or not, aqueous post-flush fluid was applied. However, only foamed ABRs allowed resin to remain on the proppant after the treated pack was overdisplaced with nitrogen gas or a nonaqueous fluid, resulting in high consolidation strength and retained permeability.

Foaming ABRs enhances the effectiveness of their placement into formation intervals by providing an effective means for diversion and better coverage, and extending treatment-fluid volume. When applied using bullheading or coiled tubing, potential applications of ABR systems include primary or remedial treatments of weakly or unconsolidated formations for sand control or fines stabilization and remedial treatments of propped fractures for proppant-flowback control.
A New Emulsified Acid to Stimulate Deep Wells in Carbonate Reservoirs
Authors: Sayed M. A. , Nasr-El-Din H. A. , Zhou J. , Holt S. , Al-malki H.
Published: June 2014

Acid treatments in high temperature deep wells drilled in carbonate reservoirs represent a challenge to the oil industry. The high temperature of deep wells requires a special formulation of emulsified acid that can be stable and effective at such high temperatures. At these high temperatures, both the reaction rate between acid and rock, and corrosion rate of tubulars are high. This fact makes protection of tubulars and reducing the reaction rate between rock and acid challenging. At temperatures above 200 °F, there is a need to add more corrosion inhibitor and corrosion inhibitor intensifier, which increases the cost of the treatment too much.

A new emulsifier was developed and used to prepare emulsified acids that can be used in stimulating deep wells drilled in carbonate reservoirs. In the present paper, the rheology of the new acid is compared to the rheology of another system formulated by a commercial emulsifier that has been used extensively in the field. All emulsified acid systems were formulated at 0.7 acid volume fraction, and the final HCl concentration varied from 5 to 28 wt% HCl. The rheology measurements were conducted at temperatures up to 300 °F for emulsifier concentration ranges from 0.5 to 2.0 vol%. The reaction between emulsified acid and rock was studied using a rotating disk apparatus at 230 °F and rotation speeds up to 1,500 rpm. A core flood study was conducted in order to study the efficiency of the new emulsified acid to create wormhole, and increase the efficiency of the treatment, especially at a high temperature (300 °F).

The results showed that the new emulsified acid system had higher thermal stability and higher viscosity than the old one. Also, the new emulsified acid system created deep wormholes at all injection rates covered (0.1 cm3/min up to 10 cm3/min), with no face dissolution encountered during acid injection. The reaction rate between emulsified acids formulated using the new emulsifier was measured using a rotating disk at 230 °F. The dissolution rate varied between 2.57E-6 gmol/cm2.s at 100 rpm and 1.09E-5 gmol/cm2.s at 1500 rpm. The diffusion rate was measured for these emulsified acid systems and was found to be around 2.73E-7 cm2/s. From these results, the new emulsifier can be used in formulating emulsified acid systems that can be used effectively in stimulation of high temperature deep wells. This paper summarizes the results of testing the new emulsified system, and recommends its use for field application in deep carbonate reservoir.