bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.