bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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 &lt; 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.