bluuebunny/crossref_metadata_2025 huggingface dataset:
Problems with Operational Pigging in Low Flow Oil Pipelines
Authors: Combe Douglas , Hair David
Published: September 2011

Pigging of pipelines within the oil industry has been around for well over 100 years and has been used as the preferred (if not the only) internal method for cleaning, maintaining operational efficiency, data gathering and inspection for integrity management purposes.

The benefits in carrying out routine "operational" pigging cannot be underestimated and operational pigging to remove water, wax, scale and other debris which is formed during routine operations whilst transporting crude oil and gas is paramount in maintaining the integrity of any crude oil and gas pipeline system. The build up of such debris is common whether the pipeline is offshore between production platforms, from a production platform to onshore or a totally land based pipeline.

Similar problems are encountered to varying degrees dependent on pipeline size, location and type of the crude product being transported.

Pipelines are normally designed for a specific maximum flowrate, this maximum rate is generally maintained on a "plateau" for several years of a field’s life, during which routine pigging operation presents little or no real problem to the pipeline operator. The cleaning pigs which are used are generally designed for the "maximum" of "potential flowrate" which the pipeline is due to see during it’s plateau phase of operation. This assumption, that these pigs will be suitable for the life of field operations, is common place with pipeline operators and as such there is a significant increase in the risk that pigs will become "stalled" on a regular basis or potentially "stuck" causing significant disruption to operation, production and in the worst case scenario a very costly subsea intervention. As can be seen from Industry Analysts1 there will be a decline in overall oil production not just from the UK Sector but from the North Sea Basin and Europe as a whole. Therefore the need to understand pigging operations in "low flow" modes of operation cannot be stressed highly enough.
Cement Zonal Isolation to Control Salt and CO2 in Brazilian Ultra Deep Water Presalt Well of Santos Basin
Authors: Gomez Julio , Passos Alexandre , Melo Alexandre
Published: September 2011

Brazil deepwater reservoirs in the presalt area of Santos basin are typically thick hydrocarbon- and water-saturated limestones. Long-term zonal isolation is required to correctly exploit the reserves, to effectively perform stimulation operations and to control water and / or unwanted gas production.

For the case presented, CO2 is expected to be produced commingled with the hydrocarbon production. Also, salt formations are present at the top of the production zone. Thus, the cement needs to include both CO2 corrosion control and salt control in order to provide long-term zonal isolation, as well as to protect the well?s casing tubulars from corrosion and from the salt-driven stresses.

This paper describes the methodology used to design a salt - and CO2 - control cement slurry, the laboratory testing performed to meet the cement requirements and the field implementation of the designed zonal isolation for a well in ultradeep waters of Santos basin. In addition to a salt layer of more than 1,000 m, the challenges for the cement sheath included gas migration and compressive strength retrogression.
Creating a World Class Safety Culture Where Two Cultures Collide
Authors: Callen K..
Published: September 2011

Creating a world class safety culture is difficult under any circumstances. Creating one culture when two distinct cultures exist is a bigger challenge. This paper is designed to provide a roadmap for how to bring two cultures together to act as one.

The Expatriates and Brasilian cultures have many similarities as well as differences. The challenge comes down to "How do you have these conversations when you do not speak the same language?" Both sides have legitimate merits for not speaking each other's language, yet there is a conflict in the perspectives. This is not a one-dimensional issue. It is not a "nice-to-have solution". It is a safety and operational issue for both contractor and operator with both human monetary cost. Once we agree on these points, both sides have to take steps.

What we did was have each person commit to learning 30 words of the other person's language. We kept it real, simple and personal. Expatriate drill crew members were asked to make a list of what 30 words, or phrases, do we need our Brasillian co-workers to know in English that would help the safety and efficiency of the drilling operations. Their Brasillian counterparts did the same for the Ex-pats. We repeated this with all disciplines on the rig. The results were fascinating. Not only did they learn the 30 words (116 people, 81% of the crew were successful) most people went beyond 30 words. The result was more than improved communications and understanding, there was a unified culture of "us". In conclusion the concept worked because learning 30 words was a stepping stone to bigger things. Once people started to use these words; risk assessments, the use of "Para" and safety conversations became more efficient with the increased communication. This has led to more personal conversations about family and career aspirations.

The significance is that you cannot create a world class safety culture when you have two cultures that are not integrated. Once the cultures come together, this sets the stage for developing a world class safety culture. The operator, contractor and individuals get a "win-win-win".
Getting Software Risk Mitigation Right from the Start
Authors: Fesas Nestor , Shafer Don
Published: September 2011

Software is the most invisible and one of the largest risks on high-specification offshore assets. For example, 40 – 56% of NPT is comprised of control systems software and hardware integration problems.1 These problems are often caused by insufficient contractual software specifications and inadequate audit and test activities which leave your assets vulnerable to risks associated with software failure including non-productive time (NPT) and health, safety and environmental (HSE) incidents.

Implementing proven methods for software risk identification, tracking and mitigation early in the asset lifecycle can help reduce these risks. A lifecycle approach (from design through to operations) helps ensure that control systems software functions as intended. Ultimately, this helps to reduce the risk of HSE incidents and prevent the additional remediation costs that can be incurred when software issues are not identified early.

This presentation will include real-life examples and will focus on lifecycle methods for reducing software risk. Topics will include: Implementation of contractual language that supports the ongoing performance of your control systemsDetermining and tracking control systems software requirements early in the lifecycle and why this activity is crucial to ongoing software risk mitigationDevelopment of effective plans for identifying and reducing software risk during operations
Integrated Management and Visualization of Unconventional Resource Evaluation Data
Authors: Cheng Kun , Wu Wenyan , Holditch Stephen A.
Published: September 2011

Information is key to evaluating the unconventional resources both with regard to characterizing the properties of geologic and petroleum systems, but also to estimating the potential of different resource types. The complex requirements for the data include: 1) integration of data with multiple types (e.g., basin general data, petroleum system data, and resource volume data), 2) display of the different patterns or correlations among the data (e.g., value distributions, geologic relationship, and geographical profile), 3) interpretation of data evaluation (e.g., numeric functions, evaluation models, and result meanings). Therefore, it is important to maintain a well-organized representation and management of data for better evaluation and decision-making.

In this contribution, the paper presents results of a resource evaluation system where the visualization method is thoroughly utilized not only to display and analyze data over multiple patterns and functions, but to enable users to clearly and easily manage data that have different types and relationships. The study was performed on a database that contains large volume of data about 25 North American basins having significant unconventional resource development. Here detailed, integrated data analysis was required for analog analysis and resource estimation to evaluate frontier basins. The solution was realized based on an integration of data visualization, management, and analysis using newly developed technologies.

It is shown that the integrated visualization and management of evaluation data helps discover the insightful relationships and patterns in different perspectives or scales, which is unattainable by traditional histograms or plots. Visualized data analysis and views highlight important results and critical factors of identifying analog basins while allowing the users to generally understand the large volume of data. In addition, the designed model enables users to manage data more efficiently, and supports the better understanding and transfer of knowledge.
Applying LWD Evaluations to Mitigate Horizontal Borehole Instability – A Case Study
Authors: May Dale H. , Kok Jeffrey , Birchwood Richard , Han Shim Yen , Peternell Ana , Blyth Matthew , Estep Nathan , Zabaldano John , Osman Haytham
Published: September 2011

In the quest to develop shale gas reservoirs, horizontal wells have emerged as the most prolific producers with lateral sections ranging from 3,000 ft to more than 10,000 ft in length in some plays. Even with substantial experience in planning and drilling in shale, borehole stability problems while drilling continue to occur, resulting in increased operating time and costs. Adding logging-while-drilling (LWD) tools to the drilling program can assist with identifying and mitigating such problems by providing valuable information on the condition of the wellbore. These measurements include ultrasonic and azimuthal calipers computed from density and photoelectric factor measurements. In this case study, time-lapse evaluation of these logs by logging on a trip out of the well revealed the presence of breakouts within the borehole and evidence of deterioration of borehole quality with time. Caliper measurements were integrated with other logs and regional tectonic information to construct a Mechanical Earth Model (MEM). The MEM consisted of estimates of rock mechanical properties, formation pressure, and in situ stresses. Using this data, a wellbore stability model was developed. The model provided insights into the stress regime and the mechanism of borehole failure. Drilling procedures to mitigate borehole breakout were consequently developed, thereby improving the efficiency of subsequent drilling in the same area.
Standards Address the Challenges of Drilling Automation
Authors: Shields John
Published: September 2011

Sophisticated applications are now available to analyze the drilling process and provide advice on the optimum operating parameters to drill safely, efficiently and to maximize wellbore productivity. The use of these applications requires a great deal of cooperation and collaboration between drilling contractors, service companies and operator personnel and systems.

Data must be exchanged between rig instrumentation systems, other rig sensors operated by service companies, downhole measurement systems, analysis applications and control systems. This data exchange must occur reliably and efficiently between different hardware systems and operating platforms.

Over the last few years a number of standards have emerged in the IT world, in industrial automation and in the oil industry. The use of these standards has the potential to bring in new levels of drilling automation capability. There are however some gaps and overlaps in the functionality and application of these different standards and an effort is required to bring these to the stage that they can be implemented and operated together efficiently.

This paper provides an overview of the work performed so far in various areas of standardization and presents some recommendations and guidelines for future development and adoption of standards that will enable reliable interoperation of drilling automation systems components.
A Multi-Domain Approach to Understanding Microseismic Data in a Tight Gas Play
Authors: Cherian Bilu V. , Villalobos Jeffrey M. , Cooley R. Duke , Panjaitan Maraden L.
Published: September 2011

In fluvial, multi-layer, tight-gas program, the acquisition of microseismic data together with the development of stress models and production models can significantly influence a development program. Often, the lack of data gathering pre and post microseismic acquisition introduces knowledge gaps that demonstrate inconsistencies between the various engineering domains. In this study, varying completion strategies and monitoring techniques were implemented together with postfracture modeling and production modeling (via rate-transient analysis techniques) to understand and explain the location of microseismic events.

This paper presents the agreements and differences observed between the stress models developed (and fracture diversion/limited entry observations), fracture half-lengths (from fracture modeling and production analysis), microseismic events and current geological understanding.
A New Analytical Method for Analyzing Production Data from Shale Gas Reservoirs Exhibiting Linear Flow: Constant Pressure Production
Authors: Nobakht M. , Clarkson C.R.
Published: September 2011

Many tight/shale gas wells exhibit linear flow, which can last for several years. Linear flow can be analyzed using square root-time plot, a plot of rate-normalized pressure versus square root of time. Linear flow appears as a straight line on this plot and the slope of this line can be used to calculate the product of fracture half-length and square root of permeability.

In this paper, linear flow from a fractured well in tight/shale gas reservoir under a constant flowing pressure constraint is studied. It is shown that the slope of square root-time plot results in an overestimation of fracture half-length, if permeability is known. The degree of this overestimation is influenced by initial pressure, flowing pressure and formation compressibility. An analytical method is presented to correct the slope of the square root-time plot to eliminate the overestimation of fracture half-length. The method is validated using a number of numerically-simulated cases. As expected, the square root-time plots for these simulated cases appear as a straight line during linear flow for constant flowing pressure. It is found that the newly-developed analytical method results in a more reliable estimate of fracture half-length, if permeability is known. Our approach, which is fully-analytical, results in an improvement in linear flow analysis over previously-presented methods.
Comparative Study of Formation Evaluation Methods for Unconventional Shale-Gas Reservoirs: Application to the Haynesville Shale (Texas)
Authors: Ramirez Thaimar R. , Klein Jim D. , Bonnie Ron J. , Howard James J.
Published: September 2011

Petrophysical evaluation methods for shale-gas plays include mineral-based workflows that use traditional nuclear, electrical, and acoustic measurements in combination with advanced geochemical logs. This approach seems to offer the most comprehensive petrophysical analysis for unconventional reservoirs as it seeks an integrated characterization of mineralogy, organic content, porous volume, and fluid distribution. However, this method requires a significant input data set and key model parameters that may not be well known e.g. mineral elemental weight fraction end points. We anticipate variability in geochemical modeling results may arise between operators and service companies, using different model(s) and parameters, or where cross-validation with core data is not possible. The role of geochemical modeling must also be understood in the context of field-wide application, as these data are only infrequently acquired.

We discuss results from three interpretation techniques applied in a Haynesville well (Texas) that were calibrated to core analyses from crushed-rock (GRI) methods. First, a multi-mineral approach that includes the standard logging suite and geochemical logs shows that independent petrophysical assessments from two vendors and those from in-house analysis are not in agreement. Second, a petrophysical model that uses resistivity and a combination of two porosity logs is proposed when only these log measurements are available. This model is readily extended to many wells with a common logging suite and may be applied in horizontal boreholes. Third, given sufficient core data across multiple wells, we apply a cluster analysis technique that provides robust results suitable for large regional studies. We compare results from each method to available core measurements and provide recommendations for further applications.

In this paper, we also study the role of laboratory NMR measurements to support reservoir characterization of shale gas. Laboratory NMR measurements on preserved core samples are performed in the "as-received" state. Core NMR porosity and water saturation values are significantly different from those of the crushed-core analysis. This observation suggests that additional laboratory NMR measurements may be required for log calibration.

The work described here provides an independent and critical analysis of multiple formation evaluation techniques applied to a Haynesville shale well with core and extensive log measurements. Results highlight the difficulty in developing a mineral-based model using geochemical logs that is consistent with both core and vendor deliverables. Interpretation of NMR data remains an elusive opportunity requiring mostly unknown formation-specific evaluation parameters.
Factors Affecting Hydraulically Fractured Well Performances in the Marcellus Shale Gas Reservoirs
Authors: Osholake Tunde , Wang John Yilin , Ertekin Turgay
Published: September 2011

Development of shale gas reservoirs has become an integral part of the North American gas supply. The Marcellus shale formation contains large amount of natural gas resources and its proximity to high demand markets along the East Coast of the United State makes it an attractive target for energy development. The economic viability of such unconventional gas development hinges on the effective stimulation of the low permeability reservoir rocks.

Horizontal wells with multi-stage hydraulic fracturing treatments are the stimulation method of choice and have been successful in shale gas reservoirs. However, the fundamental science and engineering of the process are yet to be fully understood and hence the stimulation method needs to be optimized. In this paper, we used numerical reservoir simulation techniques and quantified the effect of the following pertinent factors on the well performances and long-term gas recovery: multiphase flow, proppant crushing, proppant diagenesis, reservoir compaction, capillary pressure, and operating conditions. The knowledge generated in this study enables engineers to better design fracture treatments and operators to better manage the wells in the Marcellus shale gas reservoirs.
Application of Propane (LPG) Based Hydraulic Fracturing In The McCully Gas Field, New Brunswick, Canada
Authors: LeBlanc Don , Martel Tom , Graves Dave , Tudor Eric , Lestz Robert
Published: September 2011

New Brunswick Canada's first commercial unconventional gas field, the McCully field, is located near the town of Sussex in southern New Brunswick. The field is comprised of low permeability Hiram Brook sandstones as well as the underlying Frederick Brook shale. The McCully field started producing gas from the Hiram Brook in April 2003 from two wells and was followed by full production in June 2007. Currently there are twenty-nine wells producing from the Hiram Brook.

The Frederick Brook shale was placed on production in March 2008 and is producing gas from one hydraulically fractured vertical well. Additional wells have been drilled, hydraulically fractured and flow tested to further evaluate the development potential of the shale.

Prior to 2009, development of the McCully field has included the use of water based hydraulic fracturing to enhance production. In 2009 a fracture program based on using LPG as the fracture fluid was undertaken. Both the Hiram Brook sands and the Frederick Brook shale have been hydraulically fractured with LPG and the results have been compared to the performance of the water based fractures performed in the past.

It has been found that both clean up and initial well performance for these tight sands were significantly enhanced using LPG fracs rather than water fracs. This paper compares the clean up performance and the initial flow performance for wells fractured using the two fracturing methods.
Statistical Analysis of the Effect of Completion Methodology on Production in the Haynesville Shale
Authors: Modeland Neil , Buller Dan , Chong King Kwee
Published: September 2011

Optimizing the methodology for stimulating a shale play in early development is always a goal of the operators involved. With the Haynesville shale reservoir now well into its development, with several wells having produced 12 months or more of public production, play-wide trends can help determine which completion methodologies create the best-producing wells. The uniqueness in pressure, temperature, and lithology that characterizes the Haynesville shale creates the expectation that proven techniques of other unconventional shale reservoirs may not necessarily produce the same result in the Haynesville shale. Considering trends developed from cross-referencing completion strategies in laterals with public production, Haynesville well production appears to be heavily dependent on geographic location and total number of hydraulic fracturing treatments performed. Also impacting production are proppant placement strategies affecting conductivity (both concentration and overall volume) as well as the limited-entry clustering technique used paired with the treatment injection rate. To optimize short-term cumulative production as well as production sustainability, Haynesville well-completion strategy must focus on increasing the number of effectively stimulated fractures along the lateral as well as placing a proppant pack that will provide sustained conductivity in the adverse conditions of the Haynesville shale.
Using Data Mining to Build a Tool to Estimate the Extent of Pipeline Corrosion
Authors: Ziegel Eric , Bailey Richard , Shirzadi Shawn , Sprague Kip , Hedges William
Published: September 2011

Manual inspection data are often collected by an operator for its non-piggable pipelines to determine the state of the pipeline infrastructure across its portfolio of upstream operating locations. This inspection effort confirms the current understanding of corrosion mechanisms and the success of ongoing protective measures. With sufficient data for a pipeline, statistical estimation of the extreme wall loss value and the percentage of the pipeline that would have wall thickness less than designated important thresholds can be undertaken.

The principle difficulty in the process for estimating a worst case for corrosion is validating an appropriate statistical distribution for use in the computations. A database of wall loss measurements from in-line inspection (ILI) provided the basis for a clever data-based solution. Statistical sampling and estimation were used to create datasets for which a number of different distributions could be evaluated. The results of this exercise were used to build a statistical distribution selection algorithm that was calibrated versus statistics that could be calculated from the available manual inspection data for any pipeline.

This process for determining the expected worst corrosion for a pipeline is quick and automatic. It allows the assets to use their inspection data to easily update their understanding of pipeline condition as new inspections become available. This guides decisions for further inspection needs or possible repair requirements. The process is readily updated as new ILI's provide additional information that can be used to improve the extreme value distribution selection algorithm.

This paper builds on technology that is described in SPE 128697 (Ziegel et al 2009), which demonstrated that the adequacy of the number of inspections for a pipeline could be assessed by using the available ILI data to establish sampling distributions as the basis for sample size requirements for manual inspections. The two technologies together turn a lot of pipeline inspections into a direct awareness of the statistical assuredness of the current understanding of pipeline condition. The additional information improves the ability of inspection and repair functions to ensure that oil remains in pipelines. Loss of containment can result in millions of dollars of lost profits in a single day and have a very negative impact on the reputation of the operator.
Real-time Production Optimization in the Okume Complex Field, Offshore Equatorial Guinea
Authors: Omole Wole , Saputelli Luigi , Lissanon Janvier , Nnaji Obiageli , Gonzalez Fabio , Wachel Georgie , Boles Kim , Leon Edicson , Parekh Bimal , Nguema Nicolas , Borges Jesus , Hadjipieris Pieris
Published: September 2011

Efficient oilfield asset management requires the effective use of real-time data, model updates, and optimization of control variables to produce the most favorable choices However, the orchestration of disciplines, workflow tools and available data represents critical issues in the oil industry. In many cases, the engineer may not focus on high-impact tasks nor generate added-value opportunities. Instead, the engineer's attention is diverted to collect, manipulate and create data charts. Data collection and validation, as well as model validation and updates, are repetitive tasks that may be automated under certain conditions to relieve engineers from low- value-added tasks. Real-time production optimization (RTPO) is one component of the Digital Oil Field (DOF) that aims to solve these issues.

This paper focuses on the implementation of an RTPO system in the Okume Complex field in Offshore Equatorial Guinea. Two main challenges in this field include continuously allocating gaslift in frequently changing field conditions while minimizing production losses as well as understanding and maximizing the field production plateau. A commercial tool was used to demonstrate the value of RTPO. The implemented project supports the automation of standard workflows within the asset. The project proved several hypotheses concerning the streamlining of data capture, discipline interaction and model sustainability. Data availability and model readiness resulted as key factors from the fast and proficient implementation of the tool.

The implementation of the project reduced the time requirement for test data gathering, validating, and model updating by more than 70%. The intelligent wells achieved continuous zonal allocation while minimizing the risks of crossflow. According to the results of this work, the asset is now able to adjust gaslift settings on a daily basis for optimizing production between 1.0% and 5.1% daily. This paper presents a summary of the benefits during pilot implementation, current project status, and the next steps.
Shale Gas Developments in North America: An Overview of the Regulatory and Environmental Challenges Facing the Industry
Authors: Sakmar S. L.
Published: September 2011

The development of unconventional resources such as shale gas is one of the most promising trends in U.S. energy supplies that could have great potential for enhancing our energy independence and reducing carbon emissions. Many experts have called shale gas an "energy game changer" that could dramatically alter the energy supply picture for North America and potentially the world as other countries are just beginning to determine the extent of their own unconventional resources and are closely watching developments in North America.

At the same time, however, the hydraulic fracturing technology that is critical to unlocking the vast tracks of shale gas located throughout the United States has drawn intense criticism from environmentalists and lawmakers concerned about the potential impact of hydraulic fracturing on water supplies and the environment.

As a result of numerous health and environmental concerns raised, legislation commonly known as the FRAC Act was introduced in the 111th Congress (2009–2010) calling for greater federal regulation over hydraulic fracturing and disclosure of the chemicals used in hydraulic fracturing operations. Additionally, in March 2010, the U.S. Environmental Protection Agency (EPA) announced that it will conduct a comprehensive research study to investigate the potential adverse impacts that hydraulic fracturing may have on water quality and public health. While the FRAC Act did not reach the floor of the 11th Congress, some members of the 112th Congress (2010–2012) have recently expressed their intention to re-introduce the FRAC Act in 2011. In the meantime, hydraulic fracturing continues to draw criticism from environmentalists and EPAs scrutiny over the industry is intensifying as EPAs study starts to take shape.

This presentation will provide an overview of the legal, policy and environmental challenges associated with shale gas development in the United States. The presentation will first address the existing federal and state laws pertain to shale gas development in the United States and will also provide an analysis of any pending legislation. This presentation also provides a detailed analysis of the current EPA Study and the various environmental concerns that have been raised pertaining to hydraulic fracturing.
Imaging Techniques for 2D and 3D Characterization of Unconventional Reservoirs Core and Cuttings Samples; and How to Integrate them
Authors: Lemmens H. , Butcher A. , Richards D. , Laughrey C. , Dixon M.
Published: September 2011

Imaging of shale samples in the scanning electron microscope is typically done at different length scales. Mineralogy can be obtained by SEM/EDX at the micrometer scale. FIB/SEM analysis on the other hand typically images a field of view about ten micrometers but with a resolution high enough to distinguish nanometer scale pores. Both datasets have great value but the gap in imaging area and resolution needs to be overcome. This paper describes a first attempt at bridging that gap by making large area SEM images with both high resolution and field of view so that the locations for FIB/SEM analysis can be chosen in a more representative way.
Production Analysis of Tight Gas and Shale Gas Reservoirs Using the Dynamic-Slippage Concept
Authors: Clarkson C. R. , Nobakht M. , Kaviani D. , Ertekin T.
Published: September 2011

Shales and some tight gas reservoirs have complex, multi-model pore size distributions, including pore sizes in the nanopore range, causing gas to be transported via multiple flow mechanisms through the pore structure. In 1986, Ertekin et al. developed a method to account for dual mechanism (pressure- and concentration-driven) flow for tight formations that incorporated an apparent Klinkenberg gas-slippage factor that is not a constant, which is commonly assumed for tight gas reservoirs. In this work, we extend the dynamic-slippage concept to shale gas reservoirs, for which it is postulated that multi-mechanism flow can occur. Inspired by recent studies that have demonstrated the complex pore structure of shale gas reservoirs, which may include nanoporosity in kerogen, we first develop a numerical model that accounts for multi-mechanism flow in the inorganic and organic matter framework using the dynamic-slippage concept. In this formulation, unsteady-state desorption of gas from the kerogen is accounted for. We then generate a series of production forecasts using the numerical model to demonstrate the consequences of not rigorously accounting for multi-mechanistic flow in tight formations. Finally, we modify modern rate-transient methods by altering pseudovariables to include dynamic-slippage and desorption effects and demonstrate the utility of this approach with simulated and field cases. The primary contribution of this work is therefore the demonstration of the use of modern rate transient methods for reservoirs exhibiting multi-mechanistic (non-Darcy) flow. The approach is considered to be useful for analysis of production data from shale gas and tight gas formations as it captures the physics of flow in such formations realistically.
An Overview of Completion and Stimulation Techniques and Production Trends in Granite Wash Horizontal Wells
Authors: Srinivasan K. , Dean B. , Olukoya I. , Azmi Z.
Published: September 2011

Horizontal well completions in the Granite Wash formations of the Anadarko basin in Western Oklahoma and the Texas Panhandle approximately doubled year on year since 2006. During this period, the evolution of horizontal well completion and stimulation practices coupled with diligent identification and selection of lateral landing in high reservoir quality has resulted in significant production gains.

Various techniques utilizing large samples of well production and completion/stimulation parameters are common in high well volume resource plays to determine well performance drivers. Several studies have been done in the Granite Wash, mostly in vertical wells with multiple pay zones co-mingled. Prior studies are isolated to smaller well samples or are focused on a single well completion strategy.

This paper investigates two different areas of the Granite Wash consisting of seventy three horizontal wells in Western Oklahoma and one hundred sixty five horizontal wells in the Texas Panhandle completed in 2007 through the end of 2009. The objective is correlating completion and stimulation parameters along with lateral length with production trends. First, an overview of production trends and average probable production in different regions is presented. The second half of the paper evaluates completion and stimulation parameters including but not limited to fluid and proppant pumped per unit length of completed interval, total fluid, total proppants, lateral length, number of frac stages and average proppant concentration.
A Comprehensive Completion Study of Recent Cotton Valley Sand Well Production to Optimize Future Designs
Authors: Baihly Jason , Malpani Raj , Xu Jian , Jacob Lincy K. , Malayalam Atif , Darakhshan Jeffery
Published: September 2011

There have been over 14,000 wells drilled and completed in the Cotton Valley sand of east Texas and north Louisiana, with more than 7,900 drilled and completed since 2003. (IHS 2010) All of these wells require multistage hydraulic fractures to economically produce. Well over 180 operators have an actively producing Cotton Valley sand well. With so many operators, there are numerous completion approaches used to optimize Cotton Valley sand production, and these strategies are ever evolving over time.

The ultimate question from anyone who owns a Cotton Valley sand well is how to best complete it. By looking in-depth at more than 400 vertical Cotton Valley sand wells completed since 2003, we determined the impact of various completion parameters on production. For comparison purposes, we obtained production data on all wells and their offsets from publicly available. Well production was compared in various ways including: (1) offset wells within a 1-mi radius of the subject well; (2) normalized to the perforated interval; (3) decline trends of various completion types; and (4) delineating well groups based on production maps.

Injection rate, fluid type (i.e., slickwater versus crosslinked gel), fluid volume, proppant type, proppant amount, number of stages, etc. were objectively compared with resultant production data ranging from 1- to 5-year spans. Those completion parameters that have a significant impact on production are identified and examined, along with those factors that do not correlate to production. Completion practices that sustain a flatter decline trend are also analyzed.

Trends in the data were examined to steer the key design parameters that impact production in the Cotton Valley sand. A brief section discussing applicability of the results to other formations, including shale, is also discussed. General recommendations for a Cotton Valley sand completion are made based on the correlative production results.
Industrialization of Electrically Trace Heated Pipe-in-Pipe (ETH-PiP)
Authors: Cam Jean-Francois , Fisher Rob , Delaporte Dominique , Hall Scott
Published: September 2011

Long subsea tie-backs are increasingly considered for offshore step-out field developments, which often have intermediate or smaller reserves and complex flow assurances issues. In such cases, the flowline architecture either faces prohibitive cost for insulation requirements or, curtailment of prospect development due to the physical limits of insulation systems being exceeded. Hence, in addition to the passive thermal insulation, the heat losses must be compensated by active heating. The Total Group has identified, beside other available technologies, the Electrical Trace Heating of subsea pipelines as a promising solution, with higher energy efficiency, and ability to be energized from host platform with a limited impact, thus leading to economic optimisation.

During the last decade, anticipating the interest of the industry, Technip have run a comprehensive R&D programme on an Electrical Trace Heating solution for reeled Pipe-in-Pipe (ETH-PiP) (Denniel and Laouir, 2001 and Denniel et al, 2005) and have joined Total’s qualification programme in 2008. After more than two years of successful qualification (Denniel et al 2010 and de Naurois, et al, 2011), Total and its partners have considered the technology mature enough to allow the next step of the development: Industrialization.

Located in the Northern North Sea sector, the Islay Project, recently awarded as a full EPCI contract to Technip, has been selected as a pilot project for this technology. Whilst ETH-PiP is not the primary hydrate mitigation strategy - this is achieved by an innovative seabed conditioning strategy seeking to minimise the methanol injection requirements - Islay is an opportunity to perform full scale offshore testing and can be considered as the final qualification process for future large scale projects in both the North Sea and worldwide.

This paper details the industrialization process undertaken for ETH-PiP as part of the overall Islay Project delivery. Specific attention is drawn to the concept assessment, detailed design, project trials, assembly and offshore installation sequence to be carried out through 2010 and 2011.
How Advances In Diverless Pipeline Repair Technology Made It Possible For An Operator To Save CAPEX On The Construction Of The Deepwater Field Export Pipeline To Transport The Newly Discovered Oil To Shore
Authors: Keijser Edgar , Povloski Bo
Published: September 2011

Over the last decade, the oil and gas industry has expanded rapidly worldwide into deep and ultra deep water. Virtually all deep water field developments are dependent on pipelines.

Failure of a pipeline due to corrosion, defect or an external event can lead to loss of production and, in the worst case, can cause pollution. However, the technology to repair pipelines both in shallow and deepwater in an efficient and cost effective manner has been greatly improved and the equipment and procedures that are presently available can be considered field proven.

The cost of installing export pipelines can have an impact on the economical feasibility of a project. For certain (marginal) fields, the economics may be greatly enhanced by the proximity of existing pipelines and the ability to share and utilize these existing pipelines for the export of the newly discovered gas or oil.

However, connecting new pipelines onto existing pipelines generally implies that the existing pipeline is prepared, during the design, with a connection link to receive the new pipeline connection.

For a specific case, an existing producing pipeline network was available nearby a new oil field discovery that could potentially shorten and significantly reduce the costs of the export pipeline.

However, since the existing nearby pipeline did not have any pre-installed pipeline connection points to receive the new export pipeline, the oil company chose to install, as an industry ‘first’, a connection point in the existing pipeline subsea using equipment and procedures that was previously used only for diverless pipeline repairs.

This paper will provide a "state of the art" of how diver installed pipeline repair equipment has been developed into field proven diverless deep water pipeline repair equipment, and will develop how this deep water pipeline repair equipment was successfully used for connecting a new export pipeline onto an existing pipeline nearby thereby reducing the field development costs for the oil company.
Obtaining Real-Time Flow Rate, Water Cut, and Reservoir Diagnostics from ESP Gauge Data
Authors: Camilleri Lawrence , Zhou Wentao
Published: September 2011

Routine testing of wells with electric submersible pumps (ESPs) is usually conducted monthly to monitor liquid rates, water cut (WC), and gas/oil ratio (GOR). This monthly testing is the most common form of production and reservoir surveillance and is implemented in even the most mature fields where cost control generally takes precedence over reservoir surveillance. However, this technique has its limitations. The most common limitation is insufficient testing duration to capture a representative sample of reservoir fluids. This testing duration issue is often the case in low-flow rate and deep wells, which require several time-consuming whole or complete liquid holdup periods. Other potential problems include insufficient resolution or repeatability to identify trends in liquid and water-cut rates over short periods of time. To date, the only method for resolving these issues has been to install permanent multiphase meters on each well. Although this method has been implemented in some fields, it is uneconomical for most wells. An analytical method is described for a flow rate calculation that can be implemented in wells produced with ESPs and equipped with downhole gauges and real-time monitoring systems. These downhole gauges and real-time monitoring system provide continuous real-time virtual flow rate measurements and therefore, both liquid and water-cut trends, which deliver the required resolution and repeatability to support both well performance diagnostics and near-wellbore reservoir analysis. This technique, which has the advantage of being valid for both transient and steady-state conditions, provides instantaneous flow rate data when used with real-time data. Case studies presented will illustrate model calibration and its application to back allocation and transient analysis. Examples are provided to show how the data can be used to rapidly identify changes in productivity index and reservoir pressure across the drainage area; thereby, enabling real-time production optimization.
Environmental Regulations in the North Sea: What the Future Will Be?
Authors: Garland Emmanuel
Published: September 2011

Until now, one of the key players for the environmental regulations in the North Sea has been the Convention for the Protection of the North East Atlantic, OSPAR. But in 2008 the adoption of the Marine Strategy Framework Directive (MSFD) by the European Commission changed the deal. Although MSFD has more or less the same goal as OSPAR, it works differently and no doubt that its role will increase.

The paper, which complements two previous publications [Ref. 1 and Ref. 2], aims at clarifying the new role of both OSPAR and MSFD and developing the strategy recently adopted by OSPAR in September 2010 as well as the consequences of the MSFD. This latter requests that the member states (including Norway as the MSFD has an EEA effect) implement effective measures by 2016 at the latest. Both regulations aim at reaching a good environmental status (GES) of the maritime area by 2020. It may look as a long term, but it is not actually as it takes years to implement major changes in environment policy. The paper explains in particular the current challenging change of perspective of OSPAR regarding the implementation of a risk based approach for the management of Produced Water - a formal measure being expected to be adopted by mid 2011 -, the threat caused by the OSPAR Recommendation on offshore chemicals to be substituted by 2017, and the significant threat that the MSFD poses on seismic activities, in relation with the definition of GES on energy introduced into the water, which is linked to underwater noise. But it also develops a few other issues, less publicized (NORMs, the DRILLEX initiative, etc.). The potential impact of the measures to come may be huge (previous OSPAR measure on Produced Water cost a billion pounds to the North Sea Offshore industry) and it is important that the industry takes a role in the discussions to come.
Seaeye Sabertooth, A Hybrid AUV/ROV Offshore System
Authors: Johansson Bert , Siesjö Jan , Furuholmen Marcus
Published: September 2011

Increasing use and complexity of subsea installations has put focus on the costs of maintaining these systems. In addition, access to these systems is sometimes limited by adverse weather and ice conditions. Conventional methods for intervention, maintenance and repair (IMR) using surface ships and ROV's are very expensive furthermore are response and mobilization times slow.

To address this Saab Underwater Systems is in the process of developing a hovering Hybrid AUV/ROV system to remotely perform IMR without or strongly reduced need for a supporting ship. This system is based on the Double Eagle SAROV, a hovering Hybrid AUV/ROV in production for the military market and proven components from Saab Seaeye ROV product range.

This paper will present the Seaeye Sabertooth offshore system, its concept of operation and design. It will also present our cooperation project (Saab and Aker Solutions) for this system.
Marginal Field Life Extension: Goosander Field Case Study
Authors: McRae Gordon , Wright lulia , van Oorschot Rene , Berthereau Guillaume , Sikander Shahbaz
Published: September 2011

The full-length paper is a case study of the redevelopment of a marginal, small sized North Sea oil field and describes some of the key aspects of the process that led to the identification of a viable drilling target in a field that already had seen reasonably high recovery factors (> 25%). In particular, the use of analytical and simple numerical models to constrain key parameters before undertaking integrated full field simulation is considered.

The two main themes running through this description are, "understand before simulating" and "the quicker you fail, the quicker you succeed". There are examples illustrating how this approach allowed for parameters such as the STOIIP and vertical heterogeneity to be quantified more simply and quickly prior to integrated full field simulation modelling in the main paper.

The Goosander field is part of the Greater Kittiwake Area group of fields and is situated 95 miles East North East of Aberdeen in the UK Central North Sea.