bluuebunny/crossref_metadata_2025_split huggingface dataset:
Flow Regime Analysis Assists Early Detection of a Shallow Gas Kick
Authors: Asakereh Reza 
Published: June 2014

Abstract
An intrusion of unwanted formation fluids into wellbore in presence of drilling fluid is called a "Kick". Kick happens because either hydrodynamic pressure of drilling fluid (ECD) is not sufficient against the pressure of formation fluids or with a sufficient mud weight, drilling operation reaches to a Geopressure formation with pressure greater than the pressure exerted by the drilling fluid dynamically. Study of 172 blowout cases world-wide shows that 33% of them were shallow gases, and the consequence of more than half of these was damage to or total loss of drilling rig. In this paper, focus is on major indications of shallow gas kick, specially flowline variations, and how dynamic and motional parameters of fluid can be utilized to detect kick quickly. Anatomy of a shallow gas, include its generation and geology is explained in this paper. Positive kick indications also are analyzed. All types of gas intrusion into wellbore formulas are evaluated and 4 new first time flow regime formulas have been derived from original formulas like annular Reynolds number and annular velocity in both normal and flow conditions. A conceptional Annular Acceleration parameter has been introduced for the first time in the history of drilling engineering. Finally in the last, author suggests a real time monitoring system like those used in mudlogging units and assembled from sensors and monitoring software package that is tied with diverter system and runs the diverter operation automatically. The system can distinguish shallow gas from several events that happen in circulation system like mud weight modification, pit to pit transfer, mud dumping etc.
Identification and Quantification of Thinly Bedded Low Resistivity Pay in the Niger Delta
Authors: Mogbolu Peter O. 
Published: June 2014

Abstract
In some fields in the Niger Delta, there are reservoirs that have thin laminations of sands and shale, which contain hydrocarbons, but are either not identified as hydrocarbon bearing, or the hydrocarbons-in-place are not properly quantified. During data acquisition in wells using conventional logging tools the actual resistivity of such thin-bedded pay zones are not measured, because of the poor vertical resolution of the tools (compared to the thickness of the laminations). This results in both ‘a problem with detection’ (low contrast between the hydrocarbon pay zones and water-bearing intervals) and ‘a substantial uncertainty in quantification (and usually under-estimation) of the hydrocarbon volumes’.
In this study, an analytical approach is shown on how to properly quantify the volumes in place and recovery, starting with the proper petrophysical evaluation methods, and how the resulting properties are used to estimate the hydrocarbon volumes in the thin-bedded low resistivity pay zones.
Efficient and Robust Uncertainty Quantification in Reservoir Simulation with Polynomial Chaos Expansions and Non-intrusive Spectral Projection
Authors: Sarma Pallav , Xie Jiang 
Published: June 2014

Abstract
Polynomial Chaos Expansions (PCE) as applied with the Probabilistic Collocation Method (PCM) has been shown to be a promising approach for uncertainty quantification in reservoir simulation. In particular, it has been shown to be more accurate and efficient compared to traditional experimental design (ED). PCEs have a significant advantage over other response surfaces as they theoretically guarantee convergence to the true distribution (of the output random variable of interest, such as cumulative oil production) as the order of the PCE and number of simulations used to calculate the PCE coefficients is increased. However, there are many issues with PCM that limit the practical applicability of the method to large scale problems. A key issue with the PCM approach is that the number of simulations required to create the PCE is directly dependent on the number of terms in the PCE, and this increases exponentially with PCE order and number of random variables.
We propose the application of another related approach that also uses PCEs called Non-Intrusive Spectral Projection (NISP) that essentially eliminates many of the key problems with PCM. The main difference with PCM is that instead of using a collocation or regression approach to estimate the PCE coefficients, a sampling approach is used in NISP. This makes the number of simulations almost independent of the number of random variables and PCE order, and as a result is much more efficient for large-scale problems. Furthermore, statistically rigorous error estimates on the PCE coefficients are also provided with this approach. We also propose a robust approach for eliminating PCE coefficients that have been estimated incorrectly, thereby improving the accuracy and robustness of NISP. The accuracy and efficiency of the approach is demonstrated through various examples.
Novel, Multistage Stimulation Processes Can Help Achieve and Control Branch Fracturing and Increase Stimulated Reservoir Volume for Unconventional Reservoirs
Authors: Romanson Roch , Pongratz Reinhard , East Loyd , Stanojcic Milorad 
Published: June 2014

Abstract
In 2010, natural-gas production rates in the USA for March and April were the highest since 1974 (US Energy Information 2010). This is largely related to recent success in exploiting unconventional reservoirs and successful development and implementation of innovative technologies. In Europe, unconventional reservoirs (in particular shale gas) are receiving considerable attention. Basins with potential shale-gas plays exist, as does the infrastructure to transport gas to the end user. In addition, the gas-price scenario is favorable as well. It will be critical to find US analogs and transfer technologies/processes that will facilitate European shale-play developments into economically successful projects. However, the market and challenges in Europe are significantly different from those in the US. The population density is much higher and environmental regulations will play a different role. In addition, the entire industry is set up different with a lot less drilling rigs and other service providers. For different reasons, costs are somewhat higher than in the US as well. This demands optimization from Day 1. Directional drilling of horizontal wells needs to progress toward sweet spots, and the completion and fracturing process must be optimized starting at the first well. Therefore, it is important to understand the technologies that were game changers in the US, identify their applicability in Europe, and implement them properly.
This paper discusses two recently developed hydraulic-fracturing processes and a hybrid unit that might have considerable impact on advancing economic recovery of unconventional reservoirs. The first new process is designed for high-pumping-rate, multistage fracturing treatments with low proppant concentration. Highly concentrated proppant slurries are pumped down the coiled tubing (CT), jointed tubing (JT), or combination string, and nonabrasive, clean fluid is pumped down the annulus. In such pumping scenarios, the permanent well tubulars are saved from erosion. The pumping rate can be manipulated in real time to customize the placement and downhole-proppant concentration instantly. In case of premature screenout, a well could be easily reverse circulated and cleaned for the next stage. The combination of downhole mixing and microseismic fracture mapping provides unprecedented control of fracture execution to facilitate branch fracturing. The second new process is a combination of mechanically activated sleeve completions and fracturing of individual intervals, but with a change in the sequence in which the intervals are stimulated. This new method is proposed with a goal of altering the stress in the rock to facilitate (or enhance) branch fracturing and connect to induced stress-relief fractures in a single, horizontal well.
Riser Less Well Intervention for Subsea Work Over
Authors: Skeie Terje , Hjorteland Øyvind , Arnskov Michael Macdonald 
Published: June 2014

Abstract
The number of subsea wells has increased steadily over the years and is estimated to have exceeded 5500 by the end of 2010.
Subsea wells do in general have substantially lower recovery rates than what is normally achieved from comparable nonsubsea wells. This is due to the high intervention costs which are directly related to the rates of the rigs required to carry out such operations if the traditional and conventional approach is adopted. Hence the incentive to increase recovery rates has been limited as the balance between cost and revenue has been unfavorable, even with increasing oil and gas prices. However, this has also stimulated the development of alternative methods which can enhance recovery rates and not least address the challenges created by more fields passing maturity and exploration moving to more demanding areas.
Lightweight and riserless intervention well intervention has in this context become a proven approach with considerable potential for driving the future development. The ability to substitute large rigs with smaller and dynamically positioned light well intervention vessels has a major impact on cost and time. Riserless intervention as such has been done regularly for a number of years and has set excellent HSE standards. However, in recent years the use of riserless well intervention has become increasingly instrumental in the effort to enhance recovery rates and general performance.
The paper gives an account of a scale milling operation carried out at a Norwegian field in the North Sea where two wells both suffered from a significant drop in production.
Successful Applications of Pressure-Rate Deconvolution in the Cad-Nik Tight Gas Formations of the British Columbia Foothills
Authors: Jones Jack R. , Chen Andrew 
Published: June 2014

Summary
The Cadomin-Nikanassin (Cad-Nik) sandstone formations in the Lower Cretaceous reservoirs along the reverse-thrust faulting belt of northeastern British Columbia (NEBC), Canada, have emerged in recent years as a new tight gas play. The low porosity (3?6%) of the rock matrix controls gas storativity, while the presence of natural fractures in the form of clusters or swarms allows significant and sustainable flow rates for commercial production. Newly drilled wells are commonly hydraulically fractured to establish or enhance wellbore connectivity to the natural-fracture network.
Seismic mappings of these structural unconventional-gas reservoirs provide the early assessments of resource sizes and initial gas in place (IGIP), which usually bear large uncertainties because of the difficulty in determining reservoir structural closures and pay-porosity cutoffs. Regional analogue wells are often used to guide development decisions. Meanwhile, estimating connected reservoir volumes through conventional-gas material balances (p/z vs. cumulative production) and production-data analysis [rate-transient analysis (RTA)] has not been without challenges. Fairly long pressure buildups (PBUs), on the order of hundreds of hours, are often performed without seeing the pressure stabilization required to estimate accurately the reservoir pressure needed for material-balance calculations. The applicability of pressure extrapolation to these tests has not been systematically investigated; therefore, no reliable methods for using shorter shut-ins to estimate reservoir pressure currently exist. Thus, reliable average reservoir-pressure estimates require significantly longer well shut-in times in order to perform meaningful gas material balance. Because this is not practical, confidence in material-balance results requires a second, independent method for establishing connected well volumes to be used in comparisons and cross checking. One possible choice is RTA, but, in these fields, numerous times wellhead-pressure data are also unavailable or unreliable.
This paper presents two field-case studies that demonstrate the successful application of the pressure/rate-deconvolution approach, combining a well?s long, high-quality production-rate history with accurate downhole-pressure data from relatively short buildup tests. This approach allows the reservoir engineer to (1) reconcile the performance-based estimated-ultimate-recovery estimates with the volumetric IGIPs; (2) establish, at the least, minimum well-drainage size and connected volume; and (3) select possible infill-drilling opportunities. A final benefit is that this often leads to a better understanding of well/reservoir parameters.
Fast Track Well Surveillance and Application Integration Ready for First Oil: The Frade Story
Authors: Honeycutt David , Chacon-Fonseca Joel , Kumar Sujatha , Nelson Andrew 
Published: June 2014

Abstract
Offshore Oil and Gas operators need solutions that are ready to use, quick to deploy, and intuitive to use in order to reap the benefits that digital technologies are promising. However, all too often, issues such as complex applications and workflows, and resistance to change work together to cause unacceptable delays in deploying these solutions. This paper presents the experience of the Chevron Frade i-Field deployment project, which used out-of-the-box solutions that were configured and integrated in a short timeframe to deliver a solution that was ready for the project's First Oil.
This paper will explore how this fast-track integration was accomplished as well as the benefits that Chevron experienced as a result of the speed of its deployment. Some of the issues to be explored: The business context – Oil and Gas companies strive to mitigate risks associated with First Oil, as well as operability and production targets. The ability to monitor and provide end to end visibility to quickly diagnose the root cause of issues was critical to start-up and sustainable operations.The technologies – The project successfully deployed a real-time well performance monitoring and calculation solution, an integrated model-centric production simulation solution, and a pressure transient analysis suite that was connected to the real-time data available at the FPSO. Data was captured from data sources such as the wells, subsea equipment and facilities, then pre-cleansed to ensure quality of the calculations.The benefits – In addition to the anticipated benefits of the solution, Chevron experienced a number of unexpected benefits due to the fact that the project was up and running before First Oil. Chevron production, reservoir, and facility engineers diagnosed several field start-up teething issues. In several instances, well and FPSO stability issues were successfully diagnosed from onshore, leading to actions that reduced downtime and prevented loss of production during the startup process. This data integration effort continues to reduce the amount of time required to diagnose problems and allows for optimization of production opportunities.
Innovative In-situ Natural Gas Huff "n" Puff in the Same Wellbore for Cost-effective Development: A Case Study in Sudan
Authors: Xueqing Tang , Guocheng Li , Ruifeng Wang , Xianghong Wu 
Published: June 2014

Abstract
This paper illustrates the natural gas in-situ huff and puff pilot test applied in Jake field in Sudan. B pool of Jake field is a medium GOR (100 scf/bbl) pool with medium well productivity, averaging at 500 BOPD by PCP testing. Operator intended to increase well output to reduce operational and safety hazards. Substantial high pressure natural gas below B pool could be utilized and injected into B pool to boost recovery factor. This process undergoes injection, soaking, production, similar to steam huff and puff. Pilot test of in-situ huff and puff has been planned by following methodology: 1) driving mechanisms investigation of huff and puff and confirm applicability in B pool; 2) gas production from tubing and injection into B pool through casing without using gas compressors; 3) injection and production parameters optimization by nodal analysis;
Pilot test on two wells JS-4 and JS-1 began in Aug. 2010 and flowed naturally after 20 days injection and gained 20 fold well rate increase compared with PCP wells, amounting to 10000-13000 BOPD, setting the highest well rate record in Sudan. Conclusions drawn from pilot tests were as follows:1) in-situ natural gas huff and puff was feasible; 2) gas injection could boost reservoir pressure and reduce in-situ viscosity and enhance recovery factor; 3) gas from tubing into casing was proved simple, efficient and cost-effective 4) production rates could be optimized using nodal analysis.
Sudan is abundant in layered pools with lower gas and upper light oil, natural gas in-situ huff and puff has wide applications for similar pools in Sudan.
Successful natural gas huff and puff pilot test in this paper highlighted huge oil rate gain, innovative well bore structure, cost-effective operation, paving the way for future full field implementation.
Coupled Surface/Subsurface Simulation of an Offshore K2 Field
Authors: Dobbs Walt , Browning Brad , Killough John , Kumar Amit 
Published: June 2014

Abstract
Modern simulation capabilities were recently applied to the K2 Field to help define a risk-reducing phased development. This integrated study relied heavily on new advances to handle complex fluid behavior, derive a history match, resolve future behavior of sub-sea wells, and seamlessly review economic metrics.
Simulations used tightly-coupled surface and subsurface calculations to capture and stabilize the interaction of surface facilities with the reservoir. This robust and rigorous approach improves upon previously reported techniques in which subsurface flow calculations are only loosely coupled to the surface network. Fluid characterization involved a single equation of state with multiple distributed component sets in reservoirs and compositional mixing within the surface network. Super-critical initialization was used to represent an unusual compositional transition from a highly undersaturated oil rim to an undersaturated gas cap. History match parameters included reservoir, facilities, and well properties.
A host of development options involving artificial lift (AL), additional wells, miscible gas injection, and water injection was evaluated for economic value through an optimization-under-uncertainty approach. This assessment guided a multi-disciplinary project team to detail a short set of developments for highest consideration in a common situation where the complex interactions among the reservoir, wells, outflow network, and facilities, makes an intuitive solution inaccessible. Although the four geologic models used were considered adequately diverse for the study, further value lies in broadening the geological uncertainty and hence the range of possible outcomes.
While a relatively new application in deepwater fields, AL is recognized as a technology to extend producing life for mature fields and enable production from challenging plays such as the Gulf of Mexico lower Tertiary. Few case studies addressing such situations are available. The presented workflow may be repeated on assets with significant outflow performance drivers – assets that would benefit from modeling and resolution of complex surface/subsurface interactions.
Non Intrusive Corrosion-Erosion Monitoring for Subsea Applications
Authors: Kristiansen Sindre Halse , Instanes Geir 
Published: June 2014

Abstract
The oil and gas industry has a need for reliable monitoring of changes in wall thickness both topside and subsea. It is important to detect and monitor the effect of corrosion and erosion as this may reduce the life-cycle cost and increase the lifetime of industrial infrastructure, ships, aircrafts, ground vehicles, pipelines, oil installations, etc. Even topside the conditions of operation can be extremely hostile, facing problems like surface roughness, fluid loading issues, temperature variations, and a host of other factors that make development of a robust wall thickness assessment tool a challenging task. Deploying a monitoring system subsea makes the application even more demanding when you have to take into account factors like high pressure and limited access. Over the last years ClampOn have offered a topside corrosion-erosion monitor (CEM) for monitoring changes in the wall thickness of such infrastructure. Major advantages of this technology have been its non-invasiveness, high repeatability, high coverage and the lack of any transducer movement, also making it an excellent candidate for subsea use. The measurement principle is based on dispersion of ultrasonic guided wave modes, and by using electromagnetism these waves can be transmitted through the pipe wall without the sensor being in direct contact with the metallic surface. It is installed on the outer pipe wall to produce real-time wall thickness information, not as a spot measurement, but as a unique average path-wall thickness. With several successful installations topside, the technology has now also been made available for subsea installation.
Coiled-Tubing Technologies Improve Shale-Play Development Efficiencies
Authors: Fowler S. Hampton , Lindsay Sharlene , Smith Robert 
Published: June 2014

Abstract
Development of U.S. shale plays has greatly accelerated throughout the past decade and will continue to contribute increased production of gas and hydrocarbon liquids for many years to come. A March report by HIS-Cambridge Energy Research Associates estimates that in 2000, shale gas was only 1% of total production in the U.S., but it now makes up approximately 20% of the total production with the potential to contribute greater than 50% by 2035. The two main technologies attributed with the successful growth in shale-play development are horizontal drilling and fracturing technologies.
Coiled-tubing (CT) equipment and technologies have also aided in the rapid and economical development of shale plays. The demand for these services has increased such that a CT unit is now assigned to each frac crew. Because of CT's capability to continuously circulate, work with live-well pressure, and push to the toe of long, horizontal sections, several tools and methods have been devised to transfer these advantages to stimulation and well-servicing solutions to help optimize production while minimizing time and cost. These technologies include hydrajet and CT-conveyed perforating techniques as well as accurate placement of stimulation treatments with precise and instantaneous proppant-concentration control. Larger CT sizes are being used to enhance treatment rates, service longer horizontals, and provide additional weight or force at the end of the tubing for plug drillouts or manipulating service tools. The trend in longer and larger CT size is also driving the need to optimize the CT unit design to maintain operational efficiency and safety as well as meet Department of Transportation (DOT) regulations. This paper reviews these new CT techniques and trends being used to improve shale play developments with case histories.
The successes demonstrated in the U.S. are now being targeted at shale-play developments in the eastern hemisphere and Latin America to meet their growing demand for clean and economical energy.