bluuebunny/crossref_metadata_2025_split huggingface dataset:
Coiled Tubing Growth and the Benefits of Thinking Small Again
Authors: Stanley Rick , Terry Adrian Robert , Dean Gregory D 
Published: December 2014

Abstract
Coiled tubing has become an integral component of many well service and workover applications and programs. Its development, as we know it today, dates back to the early 1960s. While well services and workover applications still account for approximately 75% of Coiled Tubing (CT) use, technical advancements have increased the utilization of CT in both drilling and completion applications1. In recent years the industry has been trending towards drilling deeper including more highly deviated and horizontal wells. In turn this has also included larger and more complex completions. This trend has challenged the CT service providers to develop larger, more robust and innovative equipment to deploy larger coiled tubing sizes and to support increasingly difficult well bore interventions. It is important that we understand the history behind the initial small CT units (CTUs) and pipe sizes, their limitations and the evolution to the large CT unit (CTU) sizes of today. It is also important that we review some of the coiled tubing related technology advancements (such as friction reducers, small CT motors and stronger pipe development) and relate them as to how they help support the case for using smaller coiled tubing (CT) services in some circumstances. This paper describes why the industry still requires smaller CTUs and pipe sizes along with the benefits they offer today, particularly in offshore applications.
A Small CT unit utilizing smaller CT pipe has recently been developed and deployed on challenging projects in Asia Pacific to provide operators with cost effective methods to maintain wellbore integrity and enhance production. The Small / lightweight CT equipment package is very comparable to a more conventional, larger CTU spread. A Small CT package can consist of a lightweight and small footprint CT unit, a small nitrogen unit, small nitrogen tanks and compact pressure pumping equipment. As an example, for a gaslift type job using Small CT versus conventional CT equipment, the equipment foot print is reduced by 40% and the equipment weight is reduced by 46%. The small foot print and light weight of the Small CTU is especially beneficial in conditions where crane or deck space limitations are challenges.
This paper includes case histories covering the application of this Small CT technology and will review reduced operating costs, logistical support and risk exposure, demonstrating how the technology can be applied to both onshore and offshore environments worldwide. Wells that were once considered plug and abandon candidates due to economic, technical challenges or accessibility may now be candidates for Small CT technology solutions.
Overcoming the CO2 Supply Challenge for CO2 EOR
Authors: Gray L. , Goodyear S. 
Published: December 2014

Abstract
As the major fields which have been the mainstay of global oil production mature, there is a need to apply new technology and recovery techniques to extend field life and maximize economic recovery. As a result, there is growing interest in using CO2 for miscible flooding, where that is appropriate. Much of the current experience of CO2 EOR has been in the US Permian Basin, based on using CO2 sourced from high CO2 content subsurface sources. While significant CO2 EOR potential exists in many basins around the world, application of CO2 EOR is often limited by the availability of CO2 at an acceptable cost. This paper addresses the key issue of CO2 sourcing for CO2 EOR in new basins in which CO2 is the most suitable miscible fluid and the different subsurface conditions encountered with the need for subsurface/surface integration.
The full potential for CO2 EOR to increase recovery factors will only be realised if supply options can be developed for EOR projects in locations that do not have access to an existing CO2 infrastructure. Value chains linking industrial sources of CO2 to appropriate field targets are expected to be the key enabler. Robust technical and non-technical integration across the capture-transport-injection chain is required, to ensure that the potentially competing operational requirements for capture and EOR usage are reconciled, and that commercial and regulatory considerations are addressed. CO2 capture options and a methodology for developing CO2 supply options will be described and illustrated with experience from the development of CO2 value chains for CCS demonstration projects such as Peterhead, Quest and Boundary Dam.
New Acoustic-Telemetry-Operated Tester Valve for Drill-Stem Testing Operation in Deepwater - Brazil PreSalt Case
Authors: Marcançola Fernando , Martin Adam , Zeller Vince 
Published: December 2014

Abstract
Drill Stem Tests (DSTs) in exploratory wells are important for production planning, for identifying the characteristics of oil and gas, and to assess the commercial viability of the entire reservoir. A new generation of downhole test tools has been developed to address the growing challenges of reservoir testing and evaluation in the deep and ultra-deep-water environments now being explored; these new tools maintain safety as paramount and strive for greater testing efficiency in the acquisition of the reservoir information being sought in nearly all evaluation and exploration wells today. There is a growing need to better understand each well in real time as it is being tested, not only concerning the reservoir itself, but also the downhole tool mechanics critical to the testing operation. This knowledge helps to reduce uncertainties of downhole conditions, and also, helps to ensure that operations are being carried out in a safe manner and as planned. With the improvements in operational efficiency, savings in rig time also can be gained.
With the application of acoustic telemetry technology, the capability to acoustically communicate and control downhole tools in real time is achieved. Real-time data can be transmitted to and from the downhole tools, allowing on-demand control of well testing operations. The acquisition of real-time gauge data with the additional capability to actuate a new combination tester and circulating valve provides enhanced control of a DST and can provide the operator with ongoing feedback of tool position and status. This enhances the operators' ability to perform the well test with reduced uncertainties. Extending the real-time acoustic system to tool control provides the operator with additional capabilities. The operator can control downhole tools without using annulus pressure, which is not possible with the traditional DST tool systems operated with annulus pressure that restricts the number of different tools used for a DST due to casing pressure limitations. Acoustic-telemetry-controlled tools are not limited in function or number.
This paper discusses a case history in a deepwater, pre-salt area in Brazil where a new acoustic-telemetry-operated tester valve was used to successfully perform DST testing operations. This paper also discusses the new possibilities that this new tool can bring to well testing.
While the main objectives of a DST are basically the same, this new tool enables downhole well-test tools to advance to a new generation of equipment that is designed to optimize time, streamline decision making, minimize environmental and operational risks; and ultimately, help maintain safety as a priority.
Simulation Study of Hydraulic Fracturing Using Super Critical CO2 in Shale
Authors: Fang C. , Chen W. , Amro M. 
Published: December 2014

Abstract
The history of using fracturing fluid of carbon dioxide is more than three decades. Since literature concerning the application of fracturing with carbon dioxide first have been published in 1982, and utilize carbon dioxide in American shale fracturing have been success in early 1990s. Nowadays the application of fracturing fluid in shale hydraulic fracturing is general slick water, however, carbon dioxide will play an important role in shale hydraulic fracturing in the next 30 years, not only because shale gas production is rising all over the world, but also the water resources is increasingly scarce and greenhouse gas emission is increasing.
Universal Distinct Element Code (UDEC) was used to simulate pressurized cracks and hydraulic fracturing in shale with super critical carbon dioxide in this paper. First part compares the displacements of crack surface with three different fracturing fluids, water, slick water and carbon dioxide, based on assuming uniform fluid pressure, certain elastic medium, Young's modulus, Poisson's ratio, and different size of planar crack. In the second part, the assumption of Young's modulus and Poisson's ratio which reflect shale properties, brittleness and fracability were changed, and fracturing effect with super critical carbon dioxide in different shale are simulated, crack displacement were compared in these assumptions.
The simulation results suggest that viscosity of hydraulic fluid influence formation of hydraulic fractures and super critical carbon dioxide need more volume of fracturing fluid to contribute same crack displacement. Meanwhile, the performance of different shale fracability with super critical carbon dioxide fracturing fluid shows shale fracability index ranges in this model, and to some extent, using carbon dioxide as fracturing fluid have more economic and environmental significance.
Oil spill trajectory simulation for the Saltpond oilfield, Ghana, West Africa
Authors: Korsah Percy Erasmus , Anifowose Babatunde 
Published: December 2014

Abstract
The exploration and production of petroleum resources is not without environmental consequences and these remain an important factor in contemporary global oil industry. As an emerging oil producing nation, very little or nothing is known about the behaviour of Ghana’s sweet light crude in water under varying environmental conditions. This is crucial for an efficient management of accidental spills. Therefore, this study designed a deterministic model for oil spill trajectory simulation using the Saltpond oilfield (Ghana) as study location. The main objectives were to: (a) design a diagnostic GNOME model to configure and generate localised oil spill scenarios; (b) model different oil spill scenarios and weathering profiles for varying environmental conditions e.g. wet/dry seasons, different currents and wind conditions; and (c) Predict the ‘minimum regret’ Splots as a precautionary principle. A combined Eulerian-Lagrangian approach involving a hydrodynamic model containing localised environmental parameters from the Saltpond oilfield was utilised. The General NOAA Operating Modelling Environment (GNOME) based on a C++ programming language was used to execute the analyses. In addition, the ADIOS2 oil weathering tool was used to estimate the oil budget for different spill quantities based on the physical and chemical properties of Ghana’s sweet light crude at Saltpond field. The key findings are: 5000 and 10,000 barrels of spilled oil beached after a minimum of 12 hours in 97% of the scenarios under the influence of winds from the South. Wind speeds leading to beaching were 35.7% for 14 and 16 knots, 14.3% for 17 knots and 7.1% for 15 and 20 knots respectively. Weathering results showed a maximum of 43% of spilled oil evaporated after 116 hours with a minimum and maximum dispersal of 1% and 7% respectively. This study, for the first time, has provided hitherto unavailable analysis and information on oil spill transport forecasting and trajectory simulation for the Saltpond Oilfield in Ghana which environmental managers/engineers would find readily useful in responding to future oil spill disasters. The approach and methodology used in this study could also be adapted for other offshore regions in Ghana and West Africa.
Stand-Alone Wireline Oriented Perforating System Delivers New Production in a Triple Completion Well
Authors: Bou Said M. S. , Nofal S. F. , Channa Z. , Salsman A. D. , Abdel Shakour S. , Assagaf M. 
Published: December 2014

Abstract
In order to meet the production targets set by ADMA-OPCO, more focus is given to inactive strings revival by undertaking quick and economical rigless intervention operations in carefully selected candidates. The candidate described in this case study is one of several old wells that are completed with 3 x 4 ½" tubing strings run side by side in a 12 ¼" borehole and then cemented in place. Some of the wells suffer high water cut causing one or more of the strings to cease production. The plan, after checking the integrity of the tubing, was to shut off the water zone and perforate a new zone using oriented perforating technology to avoid damaging the other 2 healthy strings. The well was completed in the past using an obsolete directional perforating technology.
To shoot in the correct direction a special tool was used to orient the gun away from the other 2 strings before perforating. This tool has a shielded electromagnetic (EM) section that is sensitive to total metal thickness in the range of the measuring device. The gun and the measuring section are run into the well together on wireline and rotated by an electric motor until the gun is pointing in the correct direction. A joint task force between the ADMA-OPCO rigless intervention team and Schlumberger was created to assess the technology application and risks. Several simulations were done in a test jig built to simulate the well configuration both horizontally and vertically to assess the response of the tool. The ADMA-OPCO rigless intervention team was involved in the simulation, design and testing and have approved the operation after all the required tests were completed along with a risk assessment made to mitigate the expected risks. The job was executed successfully using the EM tool and zero phased 2-7/8″ hollow carrier guns, bringing an additional 3000 bbls of production. Confirmation that the job was successful was made by putting electronic gauges in the other two strings to record a communication test done before and after perforation. This is the first time this technique has been used in the Gulf and it has strong potential in similar environments in the area.
Challenging HPCT Scale Removal Operations in High H2S Environment Successfully Completed with Interdisciplinary Job Design and Execution
Authors: Green T. A. , Leal Jairo A. , Ginest N. H. , Al-Bu Ali M. S. , Vielma J. R. , Chacon A. 
Published: December 2014

Abstract
The carbonate gas producing zones of the Ghawar field have been impacted by extensive FeS scale deposition, reducing overall gas production and significantly increasing risks of well interventions. Previous remediation included the use of workover rigs which can be costly due to time required for workover and lost production. H2S levels (2-7%) found in the reservoir also contribute to higher costs and risks when using workover rigs.
Different chemical solutions have been utilized in similar cases and also considered for these wells, but the FeS could not be 100% dissolved with either HCl, DPTA, EDTA, GLDA blends. These chemical blends generate large amounts of H2S in addition to the already existing high levels of H2S in the formation gas. Additionally, the completion tubulars and CT were adversely affected by chemical reaction and corrosion. This poses a safety concern having large amounts of H2S in returns at surface along with potential chemical corrosion. Therefore, the safest and most economical method was to devise an effective mechanical descaling solution with CT.
This paper will discuss two case histories where mechanical descaling utilizing CT was applied. Each well had major challenges that included low reservoir pressure, increased reservoir temperature, scale with high specific gravity (3.7 to 4.3), and in the second case, horizontal open-hole sections. The low reservoir pressure required isolation methods to allow for returns to circulate out the heavy scale and to minimize fluid losses to the formation.
Following mechanical descaling with CT, the final challenge discussed in the paper is bringing the well back to maximum gas production using HPCT cleanout optimization and HPCT stimulation techniques.
Development of Streamline Simulation for Miscible Recovery Process and its Application in an Onshore Oil Field-Abu Dhabi
Authors: Bratvedt Frode , Yi Tongchun , Shaker Ashraf , Takahashi Masahiro , Didanloo Ali , Bouaouaja Mohamed , Bassiouni Mahmoud , Al Basry Ali H. , El Mahdi Ahmad 
Published: December 2014

Abstract
This paper describes the implementation of the solvent model in streamline simulation and its application to WAG injection optimization for a producing field. The solvent model was implemented as an extension to the 3-component black oil model, with solvent as an additional component, to model miscible displacement process. The relative permeabilities and fluid properties of the oil and gas phases are modified based on the fraction of the solvent component, the reservoir pressure and the Todd-Longstaff mixing-parameter (i.e. an empirical treatment of the effects of physical dispersion between miscible components).
The solvent model was applied to a Middle Eastern oilfield, which is currently under development using a miscible WAG process. PVT analysis has been done to prepare the properties for the reservoir gas and the injection solvent. Streamline simulation models with and without solvent model were run to compare the results with a reference finite difference compositional reservoir simulator and the effect of miscibility has been validated.
Results of streamline simulation models with and without solvent model were compared against a reference finite difference reservoir simulator. The comparison shows the streamline simulation model with solvent model has much better agreement with the reference finite difference compositional reservoir simulator which shows that the miscible displacement process is properly simulated in the streamline simulation model with solvent model.
The solvent model presented in this paper advances streamline simulation technology, combining the intuitive and unique properties of streamlines and the capability of simulating miscible recovery mechanism. It allows simulating both immiscible and miscible displacement within the same simulation. The solvent model considers the effects of miscibility by considering relative permeabilities and fluid properties adjustments based on pressure and solvent concentration. The technology will help effective simulation of miscible recovery process, assist optimum solvent allocation and improve unified sweep.
Jasmine Field, Gulf of Thailand: How a 7 MMbbl Oil Field Produced 50 MMbbls and is Still Producing
Authors: Oglesby C. A. , Boardman D. W. , Edwards M. , Saifuddin F. , Platt C. , Limniyakul T. , Watcharanantakul R. , Henneberg H. P. , Tabmanee P. , Maneejan R. , McClure J. , Reverdito D , Ionnikoff Y. 
Published: December 2014

Abstract
The Jasmine Field began production in 2005 with initial estimated recoverable reserves of 7 MMbbls. Appraisal continued after the initial "A" platform commenced operation resulting in significant reserve growth that allowed for the installation of four additional production platforms (B, B1, C and D) and one remote platform, Ban Yen "A", which began production in 2008. The Jasmine (and Ban Yen) Field was developed via deviated wellbores from the various platforms and was considered fully developed by late 2009. Oil production declined rapidly, accompanied by rapidly increasing water cut; leading to the perception of a short economic field life (in 2009 the end of field life was expected during 2012).
Since 2009, Mubadala Petroleum has been engaged in an active infill campaign, drilling 44 infill wells and 3 delineation wells. Delivery of this successful infill programme resulted from: Integrated study of two volumetrically significant reservoirs; the 680 and 50-sands (key targets for infill programme);Active reservoir management, increased data acquisition and reservoir surveillance activities;Utilisation of horizontal wells (usually geo-steered) to improve recovery (20 wells since 2009);Expansion of the facilities to accommodate additional well slots and water handling;Recent use of isolatable multi-zone completions to mitigate water coning/cusping.
The success of this endeavor is such that a 50 MMbbls production milestone was passed in November 2013 and end of field life continues to increase through the use of improved engineering, science and technology.
Formation Evaluation in Gas-Bearing Reservoirs Drilled with Na/K Formate WBM, Using LWD Time-Lapse Data Acquisition
Authors: Fakolujo Kehinde M. , Al-Belowi Ali , Gzara Kais , Onuigbo Oluchukwu L. , Pasaribu Ihsan T. 
Published: December 2014

Abstract
The introduction of formate-based drilling muds successfully addressed drilling challenges related to barite-weighted muds. The muds exhibited peculiar petrophysical properties that adversely affected log interpretation. First, the mud present inside the borehole and surrounding the tool required different environmental corrections; secondly invading mud-filtrate present inside the formation was difficult to account for. Because of the higher density, lower hydrogen index, and high gamma-ray readings associated with Na/K formate-based drilling fluids, for example, petrophysical analysis typically resulted in inaccurate mineralogy and pessimistic porosity and permeability estimates. Such estimates were also strongly dependent on the extent of invasion by the mud.
Two new approaches were developed to address these long-standing challenges in gas-bearing siliciclastic and carbonate sequences. Logging-while-drilling (LWD) time-lapse data acquisition makes it possible to track changes in log measurements between a first (drill) pass and a second (wipe) pass as mud filtrate invades the formation. In a first approach, these changes reflect the contrast in petrophysical properties between the mud filtrate and the displaced native formation fluids, and can be used to estimate the unknown petrophysical properties of such mud filtrate. In a second, geometric approach, the different measurements are considered to represent different axes in measurement space, and then the axes are rotated to reduce the number of rotated measurements affected by invasion to just one. This measurement is then discarded, and the remaining rotated measurements are used.
In all, up to six different petrophysical models from two different wells were compared. The results indicate a step change in petrophysical analysis in case of Na/K formate-based drilling fluids. They demonstrate how it is possible to build a robust but remarkably simple petrophysical model using only rotated nuclear measurements, with all of the following characteristics. The model is extremely stable as compared to more complex models. It requires neither knowledge of the Na/K formate mud-filtrate characteristics, nor knowledge of its volume. It does not require resistivity input, but consistently reproduces similar saturations when compared with models using resistivity as input. Data from the drill- and the wipe-pass produced identical results, independent of formation invasion.