bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Evaluation of Real-Time Mechanical Formation Classification using Drill String Vibration Measurements
Authors: Esmaeili Abdolali , Elahifar Behzad , Fruhwirth Rudolf K. , Thonhauser Gerhard 
Published: October 2012

Abstract
A drill bit creates a hole in subsurface formations by applying weight on bit and rotary speed. The bit is the first segment of the bottom hole assembly (BHA) and the drill string which contacts formation. Today it is possible to monitor drilling parameters such as weight on bit, rotary speed of drill string, azimuthal and inclination angles of the well using downhole sensors. An additional set of parameters recorded and monitored downhole near the bit is the vibration of the drill string as a consequence of the interaction between bit and different formations drilled. Dependent on formation characteristics such as the uniaxial compressive strength of rock, axial vibration is expected to change when the bit contacts formation with changing mechanical properties. Therefore, in case of using drill bits with similar characteristics, recognizing different layers of formation in real-time is expected to be possible if the axial vibration is monitored.
Experiments, using a fully automated laboratory scale drilling rig, the CDC miniRig, were performed. A vibration sensor sub is attached to the drill string above the bit. Concrete cubes with uniform strength as well as layered bonded cubes with different strength were drilled using different ranges of weight on bit and rotational speed. Higher order frequency moments were calculated and used for evaluation of the drilled concrete cubes. The cubes were built with different compressive strength and quantified by uniaxial compressive strength measurements prior to the test. The results of the experiments showed good correspondence with the expected behavior and allowed to differentiate the individual layers of concrete of different strength. The means to identify layers of rock based on vibration analysis are described in this paper. Necessary next steps to translate these results to more complex rocks are presented.
Fault-Block Transmissibility Estimation Using Injection and Production Data in Waterfloods
Authors: Bansal Y. , Sayarpour M. 
Published: October 2012

Abstract
Offshore assets instrumentation and monitoring provides a stream of under-utilized dynamic data, yet to be effectively used for reservoir characterization. This paper presents a semi-analytic approach that utilizes injection, production and pressure data to estimate fault-block transmissibility. We incorporate simultaneous pressure and rate history to determine fault status (sealing or leaking), characterize inter-fault block transmissibility, evaluate average reservoir pressure in different reservoir compartments and finally estimate effective flux rate across a leaking fault.
Analytical formulation imbedded in the capacitance resistance models (CRM) enabled simultaneous history matching of production and pressure data associated with reservoir compartments communicating through a partially leaking fault. The methodology was implemented in an offshore case study consisting of multiple fault-blocks with active aquifer support and unknown inter-block communications. We used historical injection and production rate data along with sparse average pressure data of each compartment to estimate, flux and transmissibility across the fault, between the reservoirs adjacent to the fault, and also between aquifer and reservoirs.
A material balanced based simulation model of an offshore asset was used for validation of the developed technique and sensitivity analysis of the obtained leaking fault transmissibility. This method enabled estimation of effective injection within each fault-block, the amount of aquifer support and the interaction between compartments after simultaneously history matching both rate and pressure of each compartment using CRM.
Horizontal Pressure Sink Mitigation Completion Design: A Case Study in the Haynesville Shale
Authors: Martinez Robert C. , Rosinski Josh , Dreher Doug 
Published: October 2012

Abstract
The rapid increase of US shale reservoir development has driven industry to seek innovative ways to commercially develop unconventional basins. ‘Sweet spots’ and development optimization methods within emerging plays are often not obvious. Typically, operators establish production with a single unit well to hold acreage while deferring further development. While this generally helps delineate acreage to determine geologic properties, ‘pressure sinks’ resulting from production from the initial well can impair future completion effectiveness unless steps are taken to mitigate the effects. ‘Pressure sinks’ exist in an area that has been previously stimulated or has a reduced pore pressure, which then creates a path of least resistance for a nearby, subsequent stimulation. Pressure sink mitigation (PSM) techniques are vital to a successful Haynesville shale development program.
PSM techniques applied to Haynesville shale wells represent a potential breakthrough on how to effectively mitigate the effects of pressure sinks and increase the ultimate gas recovery of the unit. Wells offset to producers completed using conventional techniques have shown poor performance relative to the unit or ‘parent’ well. In order to effectively stimulate subsequent wells, operators must stimulate the rock volume with a design that diverts fracture energy away from the existing fracture network and contacts new reservoir.
Hydraulic fracture energy follows the paths of least resistance and can propagate towards the existing unit well via the existing fracture network, planes of weakness in the rock, or natural fractures akin to breaking into a lower zone in a vertical well recompletion. Although microseismic event monitoring of fracture designs can help identify the geometry of the fracture stimulation in the original well, there is still uncertainty of the contacted fracture areal extent, actual propped volume and how unpropped areas can be activated by new hydraulic fractures. This paper presents the results and design considerations of a PSM completion progression in the Haynesville shale.
Estimating Stratigraphic Parameters from Well Test Data in Turbidite Reservoirs
Authors: Chen Tianhong , Noirot Jean-Christophe , Khandelwal Arpit , Xue Guangri , Barton Mark D. , Alpak Faruk O. 
Published: October 2012

Abstract
Well test analysis in turbidite reservoirs is complicated by the intricate stratigraphy prevailing in this depositional environment. Because of this complexity, important reservoir architectural parameters driving flow behavior (e.g., shale drape coverage, object dimensions) cannot be estimated using simple analytical reservoir models employed in conventional well test analysis techniques. Alternatively, simulation-based well test analysis offers the advantage of being able to capture stratigraphic complexity. However, it requires a very large number of models and simulations to identify multiple solutions to such a highly non-unique inversion problem. In this work, we have developed a novel well test analysis workflow by constructing a large library of build-up type curves derived by appropriately scaling a comprehensive set of reference drawdown simulations. This set is used to rapidly identify a variety of stratigraphic scenarios matching a given well test. Key stratigraphic parameters are then estimated through statistical analysis of the results. The proposed well test analysis technique has been applied to synthetic and field examples. For the tested cases, stratigraphic interpretations derived from well tests are found to be consistent with those obtained from other data sources.
Wellbore Pressure Management in Unstable Shales: It's Not Just About Rocks
Authors: Hemphill Terry 
Published: October 2012

Abstract
Much of the drilling in unconventional resource plays occurs in unstable shales, which are usually fractured and can be easily destabilized. Drilling through them successfully can be difficult at best, and many high-angled holes in these plays are often lost due to mechanical instability. This paper examines the problems of shale gas drilling from the theoretical perspective of Wellbore Pressure Management (WPM) and keys in on the effects of equivalent circulating density (ECD) while drilling and on the effects of equivalent static density (ESD) when there is no circulation.
In this paper the following questions pertaining to drilling a typical fractured shale or highly-laminated weak zone are addressed from the WPM perspective:
What mud density do I need to drill a fractured shale? Why can a typical shale gas play well be drilled with no drilling problems, yet becomes very unstable on the last trip out of the hole before wireline logging or running casing? Why are drilling problems especially acute in laminated shales or similar weak zones? Why is the wellbore unstable while the drilling density is within the range demarcated by the Safe Drilling Window? Why does shale instability often not improve significantly when drilling fluid density levels are increased? Which tools in the driller's toolbox are often used that actually make the wellbore stability issue more problematic?
By using a Wellbore Pressure Management approach to understanding instability in fractured shales, the reader can readily see how to best deal with the problem in the field and hopefully improve stability in future wells.
Gunshock Risk Evaluation when Perforating High Pressure Wells
Authors: Baumann Carlos , Barnard Keith , Williams Harvey 
Published: October 2012

Abstract
High-pressure wells are susceptible to gunshock damage when they are perforated with inappropriate gun systems. This paper presents a simulation methodology to predict Tubing Conveyed Perforating (TCP) gunshock loads reliably. This methodology enables completion engineers to evaluate the sensitivity of gunshock loads to changes in gun type, charge type, shot density, tubing size and length, use of shock absorbers, rathole length, and placement of packers, among others.
When planning perforating jobs in high-pressure wells, engineers strive to minimize the risk of equipment damage due to gunshock loads. The methodology described herein helps engineers to identify perforating jobs that have a risk of gunshock related damaged, such as bent tubing, damaged automatic gunstring release systems, and unset packers. When predicted gunshock loads are large, changes to the perforating equipment or job execution parameters are sought to reduce gunshock loads and the associated risk.
When fast-gauges are run we compare software predictions with high-speed pressure gauge data from the actual perforating jobs. Gauge pressure data shows that predicted wellbore pressure transients are accurate both in magnitude and time. Peak sustained pressure amplitudes at the gauges are on average within 10% of simulated values when the reservoir flow response is well represented. When shock absorbers are used, residual deformations of crushable elements correlate well with predicted axial loads. The methodology described herein allows engineers to evaluate perforating job designs in a short time, which in turn allows the optimization of perforating jobs by reducing gunshock loads and equipment costs.
The ability to predict and reduce gunshock induced damage in perforating operations is very important because of the high cost associated with deepwater operations. With the methodology described in this paper engineers can optimize well perforating designs by minimizing the risk of gunshock induced damage and potential rig time losses.
New Insights on Acid Stimulation of Sour Gas Wells With Flowback To Facilities Without Production Test Equipment
Authors: Paige Stephen , Redder Jos , Shepherd Andrew G. 
Published: October 2012

Abstract
This paper describes some of the operational aspects, planning practices and improvements in both coil tubing and bullhead acid stimulation campaigns carried out to increase the performance of gas-producing wells in a mature sour-gas asset. The objective of the campaign was to reduce operational costs by flowing the wells back directly into the production facilities after the treatment, without the use of temporary production test equipment. This strategy would be considered successful, if it could be proven to be technically well-executed, and compliant with HSSE directives. By engaging in a multi-disciplinary approach, critical aspects of this campaign were identified at an early stage, including selection of fit-for-purpose stimulation formulation. Furthermore a novel corrosion inhibitor capable of withstanding unspent acid in a sour system was deployed in the facilities for integrity and protection.
Key performance indicators for the campaign were set, including target pH values for flowback samples. Monitoring of H2S concentration of the produced gas was carried out, and control with the use of a H2S scavenger injected in well flowlines allowed for export gas specifications to be maintained. Overall the campaign generated significant productivity improvements. This cost-effective acid stimulation is therefore a valuable tool for well reservoir and facilities management in the asset.
Geosteering the Impossible Well: A Success Story from the North Sea
Authors: Leveque Soazig , Dupuis Christophe , Staermose Thomas , Esmerode Estela Vazquez , Linnet Peter Sommer , Raeper Graham 
Published: October 2012

Abstract
New technologies have been developed to achieve a higher degree of accuracy in well positioning as operators have been drilling increasingly challenging hydrocarbon pockets.
The Nini East Field, Danish North Sea sector, represents a significant drilling challenge. The target is a postdepositionally remobilized sand reservoir of 2–15 meters thickness. Because of the reservoir's remobilized nature and its low resistivity, none of the standard well placement methods or the current bed-boundary mapping tools were suitable solutions for the well objectives. Previous wells drilled in this type of reservoir have been marginally economical due to sidetracks and net-pay ratios below 0.5.
In view of these challenges, DONG E&P decided to collaborate to the field test of the next generation bed-boundary mapping tool to geosteer their two upcoming production wells. The technology currently in field test provides a real-time mapping of the reservoir several meters away from the wellbore. As the depth of investigation of the tool is within the same range as surface seismic measurements, the two data sources were integrated while drilling to provide look-ahead information.
The two producers achieved an outstanding 0.99 and 0.96 net-pay ratio with no sidetracks or delays and were completed within budget.
The inversion processing of deep directional resistivity measurements clearly shows the capability of this new generation tool to map the internal variations of the reservoir structure, enabling further understanding of its nature and depositional history and allowing optimization of the field development.
A Novel Workflow in Experimental Design Framework Integrating Selected 4D Seismic Measurements into Reservoir Simulation Models
Authors: Jin Long , Villa Jose , Weber Daniel , van den Hoek Paul , Pirmez Carlos 
Published: October 2012

Abstract
Quantitative integration of spatial and temporal information provided by time-lapse (4D) seismic surveys to dynamic reservoir models calls for an efficient and effective workflow. To solve this issue, we propose a novel workflow which uses a Bayesian/MCMC approach and experimental design-based proxies for selected 4D seismic observables to update dynamic reservoir models. This methodology includes the following steps: (1) create probability maps to select locations where 4D seismic data is assimilated; (2) run a sensitivity analysis; (3) create high-order proxy models; and (4) run an MCMC inversion to determine a set of models that best fit the 4D seismic data and quantify uncertainty. This new workflow has been applied in 3 cases including two synthetic models and one field case. This first synthetic example is called the Imperial College Fault Model (ICFM).The second synthetic model is a fluvial reservoir model with 10 uncertain parameters. The field example is a deepwater turbidite reservoir undergoing a waterflood with a reasonably long production history and high-quality 4D seismic data. Following the four steps of this workflow, all the models are successfully history matched by conditioning to 4D seismic data. Uncertainty quantification was also provided as part of the MCMC inversion. We also compare different scenarios using production data and/or 4D seismic data in the model updating process to show the value of the 4D seismic data. For our field case, the updated models can be used for production forecasting, reserves booking and identification of further development opportunities.
Gas Well Dewatering Pump for 23/8 inch Production Tubing
Authors: Sears Kenneth 
Published: October 2012

Abstract
This paper describes some aspects of innovative small diameter electric pump systems which are being developed to be able to be installed in 2⅜ inch production tubing using cable deployment, eliminating the need for a rig during pump installation and retrieval operations in the field. The systems can be used to economically produce deep low-rate gas wells, increase ultimate recovery and reserves by de-watering deeper mature wells, and enable production by retrofit installation through small diameter production tubing.
The downhole unit consists of a permanent magnet motor driving a pump. This concept required novel solutions in many areas, particularly motor design and electric drive, protector design, bearing and seal systems. The downhole unit includes monitoring of inlet and discharge pressures, temperature and vibration. The complete systems include cable, connectors, and the associated surface equipment which has a favourable environmental footprint.
Optimum Steam Zone Pressure
Authors: O’Dell P. M. 
Published: October 2012

AbstractOperators of steamflood projects seem to prefer low pressure steam zones in their operations. The difference between steam zone temperature and initial reservoir temperature drives all energy requirements, which are usually the largest single cost in a steamflood project. However, lower steam zone pressure implies lower drawdown available for production. And lower steam zone temperature implies higher oil viscosity and therefore lower oil production rate. The influence of steam zone pressure and temperature on oil production rate is large. Theoretically, the influence on ultimate recovery (residual oil saturation) is moderate to none. Since costs encourage lower steam zone pressure and productivity encourages higher steam zone pressure, there should be an economic optimum.The rate of change of energy requirements and oil production rate with respect to changes in steam zone temperature and pressure are determined analytically. If the reservoir geology is conducive to gravity drainage, even by a very tortuous path, then low steam zone pressure is highly favored. Lowering steam zone pressure usually comes at the cost of increased withdrawals, so it is important to carefully consider the requirements, consequences, and benefits on a case-by-case basis. A recommended method for this analysis is discussed. Significant project improvement after a pressure reduction has been reported. These production improvements and steam zone pressure in major steamflood projects are discussed.
First Application of Progressive Cavity Pumps for Appraisal Well Testing in the Ugandan Albertine Graben Basin
Authors: Sathyamoorthy S. , Steyn A. , McGilvray J. , Fuchs H. , Ainebyona B. , Kyomugisha P. , Vijapurapu S. , Kagga N. , Rindfuss R. , Basiima D. 
Published: October 2012

Abstract
Over 28 production well tests and 2 interference tests have been conducted in the Albertine Graben Basin in Uganda since the first oil discovery in 2006. The Uganda crude is moderately viscous, low GOR and later discoveries were mostly in shallow lower energy systems. In addition, Uganda crude has relatively high pour points and Wax Appearance Temperatures which result in flow assurance challenges during production testing operations. Production challenges brought about by the low energy scenario is offset by high formation permeability (mostly in the multi-Darcy range).
Field X was discovered in 2008 by Well X-1, and subsequently appraised by several wells. Zone 1 of Well X-1 was production tested under natural flow without a rig. Although hydrocarbons were brought to surface successfully during the testing operation, the maximum flow rate achieved was ca. 262 BOPD, and a stable flow rate could not be sustained. Fluid segregation effects distorted the early time data. In addition, flow assurance challenges prevented acquisition of late time response from the Pressure Build-Up (PBU). Therefore, important dynamic information, particularly with regards to flow barriers, was not obtained.
A change in completion philosophy was proposed after detailed analysis of the test results. Well X-1 was re-tested with a new completion design incorporating real-time Surface-Read-Out (SRO) pressure and temperature monitoring capability, a hydraulically controlled Inflow Control Valve (ICV), a Progressive Cavity Pump (PCP) and a surface controlled electrical heat trace system. High quality well test data was acquired and the real time data was used extensively throughout operations to optimize flow and build-up periods, and well operating envelopes. Several challenges were faced during the first completion run leading to the use of the contingent insert PCP system to re-test Zone 1.
This paper highlights the first application of a PCP completion in Uganda, and describes the challenges faced during the completion and well testing operation. The experience from Well X-1 has demonstrated that high quality exploration and appraisal well test data can be acquired using a PCP completion. Similar well completion designs will be utilized in Uganda for appraisal of other discoveries.