bluuebunny/crossref_metadata_2025_split huggingface dataset:
Tight Gas Sands
Authors: Holditch Stephen A. 
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

Introduction
Tight gas is the term commonly used to refer to low-permeability reservoirs that produce mainly dry natural gas. Many of the low-permeability reservoirs developed in the past are sandstone, but significant quantities of gas also are produced from low-permeability carbonates, shales, and coal seams. In this paper, production of gas from tight sandstones is the predominant theme. However, much of the same technology applies to tight-carbonate and gas-shale reservoirs.
In general, a vertical well drilled and completed in a tight gas reservoir must be successfully stimulated to produce at commercial gas-flow rates and produce commercial gas volumes. Normally, a large hydraulic-fracture treatment is required to produce gas economically. In some naturally fractured tight gas reservoirs, horizontal wells can be drilled, but these wells also need to be stimulated.
To optimize development of a tight gas reservoir, a team of geoscientists and engineers must optimize the number and locations of wells to be drilled, as well as the drilling and completion procedures for each well. Often, more data and more engineering manpower are required to understand and develop tight gas reservoirs than are required for higher-permeability conventional reservoirs. On an individual-well basis, a well in a tight gas reservoir will produce less gas over a longer period of time than one expects from a well completed in a higher-permeability conventional reservoir. As such, many more wells (closer well spacing) must be drilled in a tight gas reservoir to recover a large percentage of the original gas in place compared with a conventional reservoir.

Definition of Tight Gas Reservoir
In the 1970s, the U.S. government decided that the definition of a tight gas reservoir is one in which the expected value of permeability to gas flow would be less than 0.1 md. This definition was a political definition that has been used to determine which wells would receive federal and/or state tax credits for producing gas from tight reservoirs. Actually, the definition of a tight gas reservoir is a function of many physical and economic factors. The physical factors are related by Darcy's law, as shown in the stabilized, radial-flow equation, Eq. 1, (Lee 1982).
Listening to the Reservoir—Interpreting Data From Permanent Downhole Gauges
Authors: Horne Roland N. 
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

Abstract
The permanent downhole pressure gauge is a class of tool that has become popular in the industry. These tools are installed during the well completion and provide a continuous record of pressure changes during production. Permanent downhole gauges (PDGs) have potential to provide more information than is available with traditional well testing, which is carried out for a relatively short duration. PDGs may provide useful information regarding changes in reservoir properties or well conditions with time as the reservoir is produced.
However, interpretation of PDG data is a new problem. Unlike the traditional well test in which "disturbances" in the reservoir (i.e., rate changes) are created and pressure and rates are both known, the changes in rates associated with the record from the PDG may not be known. Moreover, the dynamic changes in the reservoir, along with changes in the flowing temperature or changes in the gauge itself, make the data more complicated to interpret.

Introduction
Developing petroleum resources in an optimal manner requires making many complex decisions on the basis of expectations of future reservoir performance. Central to forecasting reservoir performance is creation and calibration of a reservoir model. These interrelated tasks generally are known as reservoir description and history matching. Most data used for history matching are in the form of surface-measured rates and cumulative volumes of production (oil, gas, and water) and injection (water and gas). However, improving both the creation of a reservoir model and its calibration to replicate measured reservoir history requires collecting measurements from the reservoir itself. In many cases, these downhole data include measurements of pressure, flow rate, and temperature as functions of time. Traditionally, such measurements were made with wireline gauges. However, during the past 20 years, the application of permanently installed gauges has become increasingly common. As of 2006, the number of permanently installed gauges is probably in excess of 10,000 worldwide [Chorneyko (2006) quotes more than 1,000 for one major oil company alone].
Pushing The Limits Of Frac-Pack Operating Envelope
Authors: Furgier J. – N. , Lavoix F. , Lemesnager F. 
Published: June 2014

Abstract
Requirements for Frac-Packing long intervals in highly deviated wells are more and more frequent in many new projects. Although frac packing is a mature technology, its limits of applicability are not well known and are progressively extended by operational experience.
Today, it is a common practice to perform Frac-Pack in 65° deviated well over length of less than 100 ft and to achieve good completion efficiency (mechanical skin less than 5). This is possible with thorough engineering and QA/QC, and when accurate well data are available.
Over the last five years, Frac-Pack operating envelop has been pushed to 70 – 75° deviated wells and to lengths ranging from 100 to 322 ft. The success of such operations depends obviously on some specific precautions:
Enough information about reservoir conditions, geology and rock properties must be available to allow detailed fracture planning. In particular, time must be spent to obtain a representative mini frac and a correct interpretation; Requirements for hydraulic power and pressure rating must be properly assessed. Both the necessary pumping means and the proper down hole equipment (sand screens must be equipped with alternate path system) must be available.
The completion efficiency of such Frac-Pack is not always guaranteed. Global skin may be affected by induced (or not) partial penetration. The longer the interval, the higher the risk.
Gas Pipeline Maintenance: Safety and Environmental Issues for Operations in Highly Sensitive Ecosystems
Authors: Strappa Carla , Garzon Eduardo Tapia 
Published: June 2014

Abstract
The Ramos – Cornejo pipeline carries natural gas along 38 km from the Ramos field, in Northwestern Argentina, to the trunk pipeline network operated by TGN S.A or, alternatively, to a gas processing facility located in Campo Duran. It has a rated capacity of about 7,100,000 m3/d STD and goes through a highly sensitive environment, the "Yungas" or Northwestern Argentina's forest.
This paper focuses on how YPF (a company of Repsol-YPF group), which is responsible for this pipeline maintenance, addresses safety and environmental issues. Due to its unique features, including climate, and native flora and fauna, this location (near national parks and protected areas) requires special procedures.
The above-mentioned procedures are detailed in a maintenance handbook which describes several tasks and steps required to run the operation. Each such step is examined and documented, analyzing how it contributes to safety and environmental soundness. Environmental issues are also reviewed, particularly mitigation actions to deal with potential impacts. YPF's experience with this activity as well as empirical evidence is described.
Finally, a brief guide is proposed for use in this kind of operations in highly sensitive ecosystems.
Integrated Studies on a Conveyor Belt—A New Concept of Study Workflows Based on Stochastic Principles
Authors: Graf T. , Dandekar R. , Amudo C. 
Published: June 2014

Abstract
With multi-processor cluster computing, modular stochastic workflows and a dedicated project team, the turn-around time for project execution has been significantly reduced. Using these concepts, it is now possible to conduct integrated studies successively in a continuous chain of studies, as if they were on a conveyor belt. For example, field development planning studies for ten reservoirs, some with history of more than 20 years have been generated within one year.
The three main enabling technologies for the rapid execution of integrated studies are cluster computing and unique modular workflows that are based on stochastic concepts.
Clusters have been deployed because of its established advantage in improving performance which in this case translates into a significant reduction in simulation times. A modular workflow enables the various tasks in an integrated study to be assigned to project team members, facilitates the flow of task outcomes between project team members and creates enormous flexibility during project execution by permitting tasks to be swapped between members. Furthermore, introducing statistical methods to data handling, history-matching and risk analysis streamlines the activities and reduces the turn-around time for the various tasks.
Formation Mineralogy Impacts Scale Inhibitor Squeeze Designs
Authors: Gdanski Rick 
Published: June 2014

Abstract
Scale inhibitor squeeze designs are often developed using short-core laboratory flow tests for estimating treatment life and fluid/rock compatibility, bottle tests for reservoir fluid/squeeze treatment compatibility, and guidelines for sizing the mainstage and overflush. Laboratory tests provide a relatively high level of successful squeeze designs. However, occasionally squeeze treatments cause unexpected loss of production and short squeeze life. This paper discusses how formation mineralogy can further improve successful designs of squeeze treatments even before laboratory tests are conducted. A radial model has been used to demonstrate key principles of optimizing treatments. Previous work in this laboratory had demonstrated the importance of understanding mineralogy when fluids, such as acid or brine, are injected into sandstone formations. Many of these principles hold true for scale inhibitor squeezes. Understanding the role of formation mineralogy can help avoid unexpected compatibility problems and improve squeeze life.
In general, the mainstage of squeeze treatments should consist of no more than 5% inhibitor product at near-neutral pH. The base fluid should consist of "1-Molar" brine if swellable clays are present in oil-bearing layers of the producing well. The overflush should be sized to provide peak inhibitor returns at 2,000 to 5,000 ppm of scale inhibitor in the early returns of the treatment. As a result, typical overflush volumes range from 2 to 8 times the volume of the mainstage, depending on the formation porosity, total mineral content, and compositional distribution of non-quartz mineralogy. Compatibility of mainstages with formation fluids should be achieved with a preflush, and not by lowering the pH of the mainstage, due to dissolution of calcium carbonate and leaching of aluminum from clays.
Seeking the Ultimate Field Development Using the Well Maturity Index
Authors: Kloosterman H. J. , Herring T. R. , Tull S. J. , Van der Lee J. W. 
Published: June 2014

Abstract
A case study is presented from an oil field in the Sultanate of Oman, operated by Petroleum Development Oman. To date the field has seen limited production under natural depletion (~1% of STOIIP produced). Most of the oil is located in 20-25 m thick oil rims with large gas caps in the reservoirs of the Gharif and Al Khlata formations. A Field Study was kicked off in PDO in 2004, triggered by the results of recent appraisal wells and has substantiated significant additional field potential.
This paper extends previous work [Ref 1] in which we set out the use of Experimental Design for subsurface uncertainties analysis and development options evaluation for an oil field in the Sultanate of Oman. Here, we demonstrate for the first time how the multi-scenario ED modeling results can be taken one step further in Field Development optimisation. We introduce the concept of "Well Maturity Index" which quantifies the impact of subsurface uncertainties on EUR for each well in the selected development. The Well Maturity Index was used to guide decisions on the phasing of development and appraisal drilling and to help formulate a data acquisition programme for the field.
This approach has resulted in an auditable and quantified decision-based plan for maximizing NPV and minimising risk, and adds significant value to the development planning process. This work also provides a natural stepping stone for a quantifiable Value of Information analysis, and scenario planning based on appraisal outcomes. The methodology used is general and should find application in many field development studies..
Automatic Fracture Network Model Update Using Smart Well Data and Artificial Neural Networks
Authors: Al-Anazi A. , Babadagli T. 
Published: June 2014

Abstract
This paper presents a new methodology to continuously update and improve fracture network models. We begin with a hypothetical model whose fracture network parameters and geological information are known. After generating the "exact" fracture network with known characteristics, the data were exported to a reservoir simulator and simulations were run over a period of time. Intelligent wells equipped with downhole multiple pressure and flow sensors were placed throughout the reservoir and put on production. These producers were completed in different fracture zones to create a representative pressure and production response.
We then considered a number of wells of which static and dynamic data were used to model well fracture density. When new wells were drilled, historical and new data were used to update the fracture density using Artificial Neural Networks (ANN). More dynamic data will be provided as well as more static data when additional wells are drilled. The accuracy of the prediction model depends significantly on the representation of the available data of the existing fracture network. The importance of conventional data and smart data prediction capability was also investigated. A highly sensitive input data was selected through forward selection scheme to train the ANN. Well geometric locations were included as a new link in the ANN regression process. Once the relationship between fracture network parameters and well performance data was established, the ANN model was used to predict fracture density at newly drilled locations. Finally, an error analysis through correlation coefficient and percentage absolute relative error performance was performed to examine the accuracy of the proposed inverse modeling methodology.
It was shown that fracture dominated production performance data collected from both conventional and smart wells allow automatically updating the fracture network model. The technique proposed helps in generating another -readily available at no cost- data source for fracture characterization to be used as supplementary to limited 1-D data obtained from well logs and cores.
Optimum Economic Development of Mature Eastern European Oil Fields -Case Study
Authors: Fellner Maximilian , Duta Gabriela , Ingham Jon , Vespan Marina 
Published: June 2014

Abstract
Following the acquisition of 51% of Petrom by OMV in December 2004, the management team saw an opportunity to completely redesign their overall investment appraisal process aiming to bring it to a level comparable with the best in the industry. In particular, with the advent of the Sarbanes Oxley (SOX) legislation in the US, Petrom management wanted to achieve a level of consistency and transparency that would meet or exceed the highest international standards.
The processes in place under state ownership were focused primarily on production maintenance and lacked the economic and financial discipline required to simultaneously maximize return to shareholders. The implementation of a modern project appraisal and investment analysis system was therefore a major imperative of post-acquisition change management. In this situation availability of quality data was a major barrier to progress, however it was felt that establishing a level playing field was one of the keys for success.
Following the implementation of a suitable standard framework a business model was built for the entire Petrom E&P division using commercial software. This model was then used to forecast the outcome of several operational choices against three key strategic targets. The model contained details of more than 1,700 projects and producing fields and allowed Petrom to simulate prioritization or delay of any part of the program while honoring the links and dependencies between individual options. Goal seeking optimizers were used to find solutions that best fulfilled the corporate production target whilst staying within the established regional annual budget expenditures and other KPI's. The analysis ultimately led to selection of projects that would achieve the production and operating expenditure targets whilst requiring well below the anticipated capital budget in two of the three organizational Regions of the Romanian operations.
The paper describes how the application of business modeling practices, that have been applied effectively to long term portfolio decision making, can also be used for near term field development, capital investment, modernisation and budgetary decisions. The implementation stretched the boundaries of current practice and showed that significant insight can be gained; in particular the results show what can be achieved with far less than perfect data. An additional outcome was the accelerated development of several Petrom personnel in the application of modern business methods.
How to Optimise Oil Recovery after almost 60 Years of Production from the Matzen Field, Austria
Authors: Poellitzer Stefan , Gruenwalder Markus , Kienberger Gerhard , Clemens Torsten 
Published: June 2014

Abstract
The Matzen field is one of the largest producing onshore oil fields in Europe. The field consists of multiple stacked reservoirs. The total field Oil Originally in Place (OOIP) is about 190 million m3.
During the last years, a comprehensive effort was undertaken to improve recovery from this field. Integrated studies were performed for the main horizons and the surface facilities.
Within the long production history of the field, more and more reservoirs were found. This resulted in construction of different gathering stations in various areas of the field. Also, the flowline system was constantly modified to be able to produce the different horizons.
The studies of the main horizons revealed that a substantial potential for improved recovery exists in this field. This potential was identified and risked by using assisted history matching. A number of infill drilling locations were found. In addition, potential for acceleration of production was seen.
To maximise the value of the Matzen Field, the approach was taken to completely rebuild the surface facilities. The satellite facilities will be given-up and a new flowline system is currently constructed. The centralised facilities will have a modular setup to enable to increase gross production as needed to accelerate oil production.
The new facility setup will reduce operating costs and allow maximising recovery from this field within the next 30 years. The first results of the new development concept showed an increase of oil production of the main horizon by 30 %.
Furthermore, as part of the simulation study, technical feasibility of using the gas cap of the main field for peak Underground Gas Storage (UGS) was investigated.
A Multidisciplinary Approach Applied to a Mature Field Re-Development, Llanito-Gala Field, Colombia
Authors: Vanegas G. , Lozano E. , Gomez V. , Gonzalez R. , Montt M. , Santacruz R. 
Published: June 2014

Abstract
The Llanito-Gala field, Colombia, is a structurally and stratigraphically complex field in which the determination of productive zones in multilayer shaly sands is hindered by a low-resistivity low-contrast (LRLC) condition. Data acquisition in this field is not straightforward and several operational problems have occurred during its history. Redevelopment of this mature field with over 40 years of production depended on obtaining funding for new drilling while competing against other projects in more prolific areas.
Current technology cannot reduce the uncertainty in fluid identification for this kind of reservoirs, precluding the application of conventional methods for evaluation. The determination of objectives was performed using simple approaches, combining human knowledge with a multidisciplinary real-time work methodology as indispensable resources to minimize risk. Statistical analysis, probabilistic simulation and other basic techniques were used to determine ideal well locations and for outcome prognosis. Prior knowledge and experience acquired during drilling, discussed and analyzed by the team, were used to define well completion strategies.
The fifteen wells proposed were divided into sets of five wells to allow continuous model update and flexibility in the redefinition of drilling and completion strategies. Designing operations accurately and ensuring the preservation of the integrity of the wells proved to be crucial factors in guaranteeing results in terms of oil production. An unexpected 80% of the sands drilled by the new wells corresponded to units not previously drained, increasing the field's proven reserves in almost 5 MMBbl of oil. All new wells are oil producers, and the oil production rate of the field was doubled.
This experience, from the planning stage through to the final evaluation, is documented as a case study that can be used by other teams working under similar scenarios to learn from the strategy, efforts, errors, achievements and lessons learned.