bluuebunny/crossref_metadata_2025 huggingface dataset:
Unraveling the Myths Associated with Selecting Standalone Screens and a New Methodology for Sand-Control Applications
Authors: Chanpura Rajesh A. , Mondal Somnath , Sharma Mukul M. , Andrews Jamie S. , Mathisen Anne-Mette , Martin Frederic , Marpaung Fivman , Ayoub Joseph A. , Parlar Mehmet
Published: October 2012

Many completion engineers use laboratory sand-retention testing as a tool to select a screen for standalone sand-control applications, some focusing on prepack and others on slurry testing. Those who use slurry tests for screen selection typically do so based on the conventional wisdom that slurry testing is more challenging; thus, it represents the worst-case scenario for sand production. Furthermore, the general belief in the industry has been that metal-mesh screens with a "pore structure" are better for sand retention compared with wire-wrap screens (WWS) of slot geometry, although they are more prone to "plugging." These are just a few of the many myths that exist in screen selection for standalone screen (SAS) applications.

Recent papers on modeling of sand retention by screens of various geometries, and supported by laboratory experiments, provided the tools for predicting sand production in both prepack and slurry conditions, as well as allowing for a systematic performance comparison of various screens using the entire particle-size distribution (PSD) of formation sands (Chanpura, Fidan et al. 2011; Chanpura, Mondal et al. 2012; Mondal, Sharma, Chanpura et al. 2011; Mondal, Sharma, Hodge et al. 2011).

In this paper, we discuss and challenge many myths in screen selection for SAS applications and substantiate our findings with modeling and experimental data. The conditions under which a slurry or a prepack test would be more conservative are identified, highlighting the mechanisms of sand retention (size exclusion or bridging dominated). We demonstrate the current thinking that prepack tests are always more conservative from a sand production standpoint is incorrect. We also show that the concept that metal-mesh screens are always superior for sand retention than WWS is incorrect, highlighting the factors that affect sand production through various screens (open flow area (OFA), wire thickness, fraction of bridging-size particles in the formation sand etc.). Finally, a methodology for screen selection in SAS applications is proposed.
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

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

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

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

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

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

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

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

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

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

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

Operators 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

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.
First Horizontal-Well Production Logging and Water Control Success in a Tough Completion Offshore Well: A Case Study from China
Authors: Zheng Yongjian , Li Yaolin , Zheng Huaan , Yuan Hui , Dong Jiayong , Guo Hongzhi , Cheng Chang , Liu Weimin
Published: October 2012

The Wen Chang oil field in the South China Sea is exploited mainly with horizontal wells completed with a sand screen and equipped with an electrical submersible pump (ESP) plus Y-tool for the production string. The water cut in one well has reached 74%, making diagnosis of the water entrance critical for a success remedial operation in the well.

Because flow regimes in highly deviated and horizontal wells are quite different from those in vertical wells, the velocity and holdup distribution are required for accurate flow rate and fluid entry determinations in multiphase flow. In addition to the sand screen completions and variation in the well trajectory, the presence of annulus flow makes the measurements even more complex. Production logging in horizontal wells can be challenging. An array of mini-spinners with optical gas and resistivity water holdup sensors was conveyed by an electrically powered tractor in the well along a 730-m horizontal interval. Two difficulties in conveying the tool string to TD were that the 5½-in. screen liner is directly hung inside 9 5/8-in. casing without entry guide and that the minimum restriction of the Y-tool bypass tubing is only 2.313 in, so the tool can easily be stuck inside the tubing. These difficulties were overcome by using a specially designed tool string. The operation was successful and high-quality logging data was acquired. Comprehensive interpretation shows that 74.7% of the water comes from the bottom 50-m interval. Recirculating water was also observed in the deviated interval.

Based on the production log analysis and reservoir permeability distribution from logging-while-drilling data, a two-stage annulus chemical packer (ACP) was designed, with one stage to shut off the current bottom water entry and the other prepared for future water control. A production tubing string with flow control nozzles was installed after water shutoff to optimize fluid distribution along the interval. Water was successfully shut off in this horizontal well.
Petrophysical Properties of Unconventional Low-Mobility Reservoirs (Shale Gas and Heavy Oil) by Using Newly Developed Adaptive Testing Approach
Authors: Hadibeik Hamid , Chen Dingding , Proett Mark , Eyuboglu Sami , Torres-Verdín Carlos
Published: October 2012

Pressure testing in very low-mobility reservoirs is challenging with conventional formation-testing methods. The primary difficulty is the over-extended build-up times required to overcome wellbore and formation storage effects. Possible wellbore overbalance or supercharge are additional complicating factors in determining reservoir pressure. This paper addresses the above technical complications and estimates petrophysical properties of low-mobility formations using a newly developed adaptive-testing approach.

The adaptive-testing approach employs an automated pulse-testing method for very low-mobility reservoirs and uses short drawdowns and injections followed by short pressure stabilization periods. Measured pressure transients are used in an optimized feedback loop to automatically adjust subsequent drawdown and injection pulses to reach a stabilized pressure as quickly as possible.

The automated pulse data is used to determine supercharge effects, formation pressure, and mobility via analytical models by analyzing the entire pressure sequence. A genetic algorithm estimates additional reservoir parameters, such as porosity and viscosity, and confirms results obtained with analytical models (reservoir pressure and permeability). The modeled formation pressure exhibits less than 1% difference with respect to true formation pressure, while the accuracy of other parameters depends on the number of unknown properties. As a quicker method to estimate reservoir properties, a direct neural-network regression of pulse-testing data was also investigated.

Synthetic reservoir models for low-mobility formations (M < 1 μD/cp), which included the dynamics of water- and oil- based mud-filtrate invasion that produce wellbore supercharging were developed. These reservoir models simulated the pulse-testing methods, including an automated feedback-optimization algorithm that reduces the testing times in a wide range of downhole conditions. The reservoir models included both simulations of underbalanced and overbalanced drilling conditions and enabled the development of new field-testing strategies based on a priori reservoir knowledge. The synthetic modeling demonstrates the viability of the new pulse-testing method and confirms that difficult properties, such as supercharging, can be estimated more accurately when coupled with the new inversion techniques.
Quantifying Proved Undeveloped Reserves in the Woodford Shale: A Seamless Integration of Statistical, Empirical, and Analytical Techniques
Authors: Kulkarni Madhav M. , Cox Stuart A. , Woods Marcelyn E. , Van Meter Gregory M. , Jensen Timothy R. , Altemus Rebecca L.
Published: October 2012

Although not all analytical, empirical, and statistical techniques are applicable at all stages of field maturity, their concurrent and consistent application was indispensable in justifying the Woodford as a World-Class Tier 2 Resource play (SPEE Criteria 2010) and added multiple Proved-Undeveloped (PUD) locations in 2011 that were not direct offsets. Introduction of the "Modernized SEC Rules" greatly expanded the scope of tools available for evaluating and justifying PUD locations more than one offset away from the existing producers. Shale Plays - with their monumental extent, number of wellbores, drilling activity, and in-place volumes - provide a quintessential laboratory to test application of advanced statistical approaches, in conjunction with analytical and empirical protocols for the play evaluation.

The starting point for the PUD evaluation was the protocol advocated in the recently published SPEE Monograph 3. The employment of statistics required the development of a large dataset of projected EURs, which was generated using an inhouse decline curve analysis protocol and validated using an empirical model. Analytical correlations were also employed to achieve the sample size dictated by uncertainty analysis of the data. Then, this synthesized dataset was benchmarked against G&G parameters to determine if the entire area met the SEC definition of "analogous formation." Finally, advanced statistical techniques were applied to define the "Reliable Technology Area" (RTA) in the play and the Proved volume.

The resulting statistics for the RTA established using this protocol were found to be remarkably consistent and reproducible, thus meeting the SEC's definition of "Reliable Technology." The resulting Proved area was further refined using PVT data and economics. The scope of this paper is limited to the elucidation of the successful application of this integrated Technique to the Anadarko-Woodford. Additional results would likely be presented in future papers as this methodology appears to be highly transferable to other resource plays.
New Insights into Microscopic Fluid/Rock Interaction: MR-CT Microscopy Approach
Authors: Kwak Hyung Tae , Funk James J. , Al-Nakhli Ayman R. , Balcom Bruce
Published: October 2012

In the current work, we propose a new suit of core analysis tools, called MR-CT Microscopy. Nuclear magnetic resonance combined with X-ray computed tomography improves the description of pore property changes as the result of core flooding with various types of fluids. With its ability to offer spatial fluid-rock interaction information with proper mineralogy quantification, MR-CT Microscopy offers a new opportunity to observe microscopic events within reservoir porous media without damaging the sample. To demonstrate the benefit of the proposed analytical tool, core flooding test were performed to investigate chemical stimulation treatment for a set of Upper Jurassic carbonate core plugs from Saudi Arabia.
Improved Detection of Bed Boundaries for Petrophysical Evaluation with Well Logs: Applications to Carbonate and Organic-Shale Formations
Authors: Heidari Zoya , Torres-Verdín Carlos
Published: October 2012

Petrophysical interpretation of well logs acquired in organic shales and carbonates is challenging because of the presence of thin beds and spatially complex lithology; conventional interpretation techniques often fail in such cases. Recently introduced methods for thin-bed interpretation enable corrections for shoulder-bed effects on well logs but remain sensitive to incorrectly picked bed boundaries.

We introduce a new inversion-based method to detect bed boundaries and to estimate petrophysical and compositional properties of multi-layer formations from conventional well logs in the presence of thin beds, complex lithology/fluids, and kerogen. Bed boundaries and bed properties are updated in two serial inversion loops. Numerical simulation of well logs within both inversion loops explicitly takes into account differences in the volume of investigation of all well logs involved in the estimation, thereby enabling corrections for shoulder-bed effects.

The successful application of the new interpretation method is documented with synthetic cases and field data acquired in thinly bedded carbonates and in the Haynesville shale-gas formation. Estimates of petrophysical/compositional properties obtained with the new interpretation method are compared to those obtained with (a) nonlinear inversion of well logs with inaccurate bed boundaries, (b) depth-by-depth inversion of well logs, and (c) core/X-Ray Diffraction (XRD) measurements. Results indicate that the new method improves the estimation of porosity of thin beds by more than 200% in the carbonate field example and by more than 40% in the shale-gas example, compared to depth-by-depth interpretation results obtained with commercial software. This improvement in the assessment of petrophysical/compositional properties reduces uncertainty in hydrocarbon reserves and aids in the selection of hydraulic fracture locations in organic shale.
Surfactant Prefloods for Integrated EOR in Fractured, Oil-Wet Carbonate Reservoirs
Authors: Fernø Martin A. , Haugen Åsmund , Graue Arne
Published: October 2012

In laboratory experiments a surfactant was injected into the fracture of an oil-wet fractured limestone to alter the wettability of the fracture surface to increase waterflood oil recovery. After a short shut-in period, the system was waterflooded to study the fluid transport from the fracture to the matrix and the oil recovery. The results were compared with waterfloods without surfactant treatment to isolate the effect of wettability changes on the fracture surface during water based EOR in oil-wet, fractured carbonate reservoirs. Differential pressure across each matrix block was measured, and magnetic resonance imaging (MRI) was used to obtain dynamic in-situ fluid saturation distributions, both in the matrices and within the fracture itself. A capillary threshold pressure for water to invade the matrix blocks was observed. Waterfloods after surfactant treatment demonstrated the benefit of changing the fracture surface wettability, leading to water transport into the downstream matrix block with no need to overcome the threshold pressure. Changes in fracture surface wetting preference were also confirmed visually in-situ by MRI imaging.
Assessment of Barium Sulfate Scaling in Conventional Gas Well Production using Real-Time Monitoring
Authors: Emmons D. H. , Pagel Ryan W. , Linares-Samaniego Sandra , Savage Jermey , Sweeney Timothy , Thomas Lawrence E.
Published: October 2012

Scaling has been a major concern in a conventional gas condensate well production facility in northwest Louisiana. Severe barium sulfate deposits have been noted throughout the facility causing operational issues resulting in increased lifting costs. The production is primarily from two formations, the Cotton Valley and Hosston. The Hosston has relatively high sulfate while the Cotton Valley has relatively high barium. Combining these waters creates a barium sulfate scaling environment similar to worst case North Sea or Gulf of Mexico examples.

The applications of a bench-top scale deposition monitor as well as a real-time monitor are described. The use of both techniques is illustrated by presenting results of field testing performed at location to get a better understanding of the severity of the scaling problem as well as the treatment rate of scale inhibitor necessary to control scaling.

The rate of scaling was determined for the Hosston and Cotton Valley waters, independent of each other and also as mixtures of the two, using the bench-top monitoring technique. The rate of scaling of the combination of the waters was an order of magnitude greater than either of the waters by themselves. The inhibitor dosage required to inhibit scale was also determined and reported for each water condition.

Real-time monitoring was conducted in the facility at a point just prior to water disposal. The results obtained to date agreed with the bench-top monitor results. Inhibitor treatment is currently being adjusted based on real-time monitoring to optimize field treatment and further validate the bench-top method.
Well Abandonment: Abrasive Jetting to Access a Poorly Cemented Annulus and Placing a Sealant
Authors: Zwanenburg Mirjam , Mulder Ger , Schoenmakers Jules
Published: October 2012

This paper describes a method for well abandonment using Coiled Tubing. It provides a rigless well abandonment technique for wells that suffer from sustained casing pressure (SCP) in one or more annuli.

The method uses abrasive jets for cutting holes into casing(s). The holes cover the full circumference of the casing, i.e. 360 degrees. This is performed at two depth levels, spaced 5 meters apart (adjustable). The assembly can be run on coiled tubing and rotated using an indexing tool. After placing a retainer plug between the two depth levels, a sealant material can be squeezed behind the casing to stop the Sustained Casing Pressure or gas percolation in the annulus.

A full-scale yard trial of the system is presented in this paper. The tool design, testing procedure, and results are discussed. The system is currently nearing the end of the testing phase.
Inclination Effects on Flow Characteristics of High Viscosity Oil/Gas Two-Phase Flow
Authors: Jeyachandra Benin Chelinsky , Sarica Cem , Zhang Hong-Quan , Pereyra Eduardo
Published: October 2012

The effect of downward and upward pipe inclinations on flow characteristics for high viscosity oil-gas two-phase flow was experimentally studied. 400 experimental tests were conducted in a 50.8-mm ID pipe for ±2° inclinations. Four different oil viscosities, namely, 0.585, 0.378, 0.257 and 0.181 Pas, were considered. Superficial gas and liquid velocity varied from 0.1 to 3.5 m/s and 0.1 to 0.8 m/s, respectively. Flow pattern and pressure drop are reported. The experimental results were used to evaluate different flow pattern maps, models and two-phase flow correlations.
Search for Unconventional Gas in Asia Pacific Region: Chinese Cambrian Age Marine Qiongzhusi Shale Gas Play: Case History, Operation, and Execution
Authors: Zonggang LV , Wang Lin , Deng Sufen , Chong King Kwee , Wooley James S. , Wang Qiang , Dumesnil Joe
Published: October 2012

During the past five years, shale gas developments have changed the game for the US natural gas industry. Globally, shale exploration activities are also increasing. China is in the early stages of exploiting the world's largest reserves of shale gas resources while attempting to cope with increasing energy demands.

This paper presents a case history of applicable technology currently used in North America for initial attempts at shale gas exploration in China. This case study is the first Cambrian age marine shale well in the Qiongzhusi formation located in the shale-gas-rich Sichuan province.

Many technologies were brought from North American shale gas applications for this well. (Chong et al. 2010). This study describes the technologies used to drill and complete the targeted shale gas formation and guide the completion and stimulation design. The target formation was drilled horizontally and the casing was cemented. The formation was then stimulated with multiple stages after full integration of data from geologic, geomechanical, petrophysical, and core analysis, which aided in the fluid and proppant selection, proppant concentration, and the designed injection rate. A diagnostic fracture injection test (DFIT) was performed before the main treatment to confirm fracture gradient, closure, pore pressure, system permeability, and leakoff. Microseismic mapping was also used, which proved to be very valuable when planning and assessing the fracturing results.

Currently, the well is flowing gas at rates comparable to early production time in a typical North American shale gas well with a similar type of completion.

This case study serves as an example of successful implementation of proven technology outside of the North America shale gas market. Continued projects such as this one are the predecessor to full-scale development of shale gas and have helped shape the abundant gas supply now in the United States. Additionally, these types of projects are necessary to help China improve their future outlook on gas supply.
Effective Mitigation of Tool Sticking Risk in Formation Testing and Fluid Sampling Operations
Authors: Prasad Tushar , Castillo Homero C. , Elshahawi Hani
Published: October 2012

The increased use of deep, highly-deviated and tortuous wells has increased the risk of wireline logging tool strings getting stuck downhole. If this risk is not appropriately managed and effectively mitigated, significant financial exposure can result from the cost of the multi-day fishing operations, the lost-in-hole and replacement charges, and -most importantly-the loss of opportunity to acquire critical subsurface data. This exposure is even higher in environments with large operating costs, such as deep water.

Historically, formation testing and fluid sampling tools have been among the most frequently stuck, fished and lost logging equipment. On the other hand, formation testing continues to provide some of the most essential information for reservoir characterization. Therefore, managing the risks associated with tool deployment is essential.

This paper discusses the sticking mechanisms of formation testing and fluid sampling tool strings, and provides specific recommendations for the planning and execution of such operations. The various factors that lead to differential sticking or keyseating of the tool string and the wireline cable are discussed. A dataset that explores a wide variety of situations is analyzed to provide a pragmatic guideline for effective mitigation of tool and cable sticking. A specific example from highly deviated deep water well is shown to highlight the significance of proactive planning.
Can A Shallow Frozen Reservoir Be Successfully Exploited? A Predevelopment Case Study Of The Umiat Oil Field, Northern Alaska
Authors: Hanks Catherine , Shimer Grant , Ahmadi Mohabbat , Oraki Kohshour Iman , McCarthy Paul , Dandekar Abhijit , Mongrain Joanna , Wentz Raelene , Davis Jeremy
Published: October 2012

The Umiat field in northern Alaska is a shallow, light oil accumulation with an estimated OOIP of ~ 1.52 billion barrels with 99 bcf associated gas. The field was discovered in 1946 but was never considered viable because it is shallow, in the permafrost, and far from any infrastructure. Modern drilling and production techniques make Umiat an attractive exploration and production target. However, little is known about the behavior of a rock/ice/light oil system at low pressures. This information and a robust reservoir model are needed to evaluate the effectiveness of different production methods in this type of accumulation.

Umiat consists of shoreface and deltaic Cretaceous sandstones deformed by a thrust-related anticline. New data indicate the reservoir has six facies associations with distinctive permeability trends. These trends combined with diagenetic effects and natural fractures impart a strong vertical and horizontal permeability anisotropy to the reservoir that needs to be accounted for in reservoir simulation.

Understanding rock and fluid behavior under these conditions is critical for valid simulations. Experimental and theoretical studies indicate that there is a significant reduction in the relative permeability of oil in the presence of ice, with a maximum reduction when connate water is fresh and less reduction when water is saline. The small amount of available Umiat oil was severely weathered and limited traditional PVT and phase behavior analysis. A unique method was developed to physically recreate a pseudo-live reservoir oil sample by comparing the composition of the weathered Umiat fluid with a theoretical Umiat composition derived using the Pedersen method.

These data are being integrated into a simulation model to test production techniques such as cold gas injection. Success at Umiat will pave the way for development of a unique class of Arctic reservoirs.