bluuebunny/crossref_metadata_2025_split huggingface dataset:
Stressed Rock Penetration Depth Correlation
Authors: Harvey J. , Grove B. , Zhan L. 
Published: June 2014

Abstract
Downhole shaped charge depth of penetration (DoP) prediction has historically been largely determined by API Section I unstressed concrete performance. As previously reported [1, 2], reliance on unstressed concrete performance is flawed for several reasons and a review of industry models motivated a new approach based on stressed rock experiments.
As a result of a multi-year extensive experimental program, shaped charge DoP into stressed rocks is found to decrease exponentially with an empirically determined formation parameter; the ballistic indicator function, FBI. This parameter which combines formation intrinsic properties (UCS, porosity) and extrinsic properties (overburden stress and pore pressure) is described as well as its integration into an improved downhole shaped charge prediction model.
The development of the ballistic indicator function required approximately 600 single-shot experiments spanning 4 shaped charges, 10 different rocks (sandstones and carbonates), overburden stresses from 1 ksi to 20 ksi, and pore pressures from zero to 10 ksi. A recommended test program is presented which currently requires as few as 12 single-shot experiments for each charge to determine two charge-dependent parameters: the reference DoP, DoPref, and the exponential coefficient, α0. These two coefficients are sufficient for FBI&lt;25 ksi which represents the majority of reservoirs currently being perforated world-wide. For reservoirs in excess of 25 ksi, DoP approaches a non-zero limit which is charge-dependent, and a preliminary discussion of this limit is included.
This model was initially developed based on sandstone targets. A preliminary extension of this model to carbonate targets is also presented. In general, carbonates behave differently than sandstones with less stress dependence and shallower penetration depths.
A CT Scan Aided Core-flood Study of the Leak-off Process in Oil-based Drilling Fluids
Authors: van Overveldt Andrea S. , Guo Hua , de Blok Gerard , Bedrikovetsky Pavel , Zitha Pacelli L. 
Published: June 2014

Abstract
The leak-off of oil-based mud (OBM) into sandstone cores was studied both theoretically and experimentally. Simple models were used to describe the build-up of the external filter cake and the internal filtration of small particles. Then systematic static leak-off experiments were done using an innovative method where CT scans taken at time intervals were used to visualize and accurately quantify infiltration of fluids into sandstone cores. This method allowed the monitoring of the leak-off process in a way that could not be done by the traditional API filter paper press test. The composition of oil based drilling fluids was varied, to investigate the influence of various particles on the leak-off process. Scanning electron microscopy (SEM) was used to characterize the external filter cake and internal filtration. The core flow experiments were matched to the theory for linear static filtration. The results lead to new insights concerning the build of external filter cake and internal filtration. This work creates a basis for future improvement of oil-based mud, by providing a better understanding of mechanisms involved in leak-off process and its control.
Simulation of Shale Gas Field Development: An Example from Western Australia
Authors: Göedeke Stefan , Hossain Md Mofazzal 
Published: June 2014

Abstract
Shale gas exploration activities have been growing rapidly in Australia. A flow rate of up to 2 MMSCFD has been reported recently from the first exploratory vertical well in the Cooper Basin in South Australia. Perth and Canning Basins in Western Australia are also reported to be highly prospective. However, shale gas production differs from conventional reservoirs primarily because of extremely low permeability and other petrophysical characteristics. Commercial production requires massive hydraulic fracturing often in long horizontal completions.
The potential development of a shale gas field in Western Australia has been simulated to optimize production and minimize development cost through sensitivity analyses. Conditions in Australia are particularly challenging often because of significantly higher costs in drilling, completion and fracturing than those of the US. The minimum number of wells and the maximum Net Present Value (NPV) was iterated by simulation. The factors influencing their overall success of the field development project were investigated in order to generate a workflow model suitable for a variety of cases. The influence of well fracture and other parameters such as completion length, fracture geometry, permeability and gas price was tested against NPV to optimize the development. Optimization of any development should be possible by iterating on any parameter and the related variables. Whilst in conventional gas there is a clear understanding of what is economically viable, this is not the case in shale gas particularly in Australia. Before embarking on any drilling, testing or development activities simulation sensitivity studies of this nature are essential.
Comprehensive Approach to Production Stimulation of Massive Cold Heterogeneous Carbonate Formation using Coiled Tubing
Authors: Dnistrjanskij Vladimir , Mokshaev Aleksander , Bogatyrev Oleg , Ilgildin Ruslan , Kayumov Rifat , Burdin Konstantin , Lobov Mikhail 
Published: June 2014

Abstract
The Orenburg oil, gas and condensate field (OOGCF) is one of the largest fields in the Volgo-Urals region of Russia. It is characterized by complex formation lithology, underlying water, low bottomhole temperature and significant reservoir depletion making successful matrix acidizing particularly challenging. Existing wellbore equipment prohibits the use of inflatable packers. Therefore only chemical diverters can be used for treatments. Thorough engineering and previous acidizing experience in this region lead teams to select the following technologies to account for all challenges in stimulation on OOGCF: Viscoelastic self-diverting acid (VSDA). Based on viscoelastic surfactant, VSDA initially has low viscosity. However, while the acid spends, the fluid viscosity increases, redirecting flow to less permeable zones. After the treatment, viscous VSDA losses its viscosity when it comes in contact with hydrocarbons and/or solvent pumped in the preflush stage. Absence of polymers in VSDA eliminates risk of formation damage.Selective diverter for temporarily blocking water-producing zones. This water-based fluid with viscoelastic surfactant initially has high viscosity. During matrix acidizing treatment, the selective diverter is injected into all zones. Its viscosity sharply drops in the hydrocarbon-saturated zones while maintaining stability in water-saturated intervals, thus preventing acid injection in undesirable zones.Foam diverter allows foam to be generated in the matrix and temporarily plug the pore spaces. This causes temporary plugging of the acid-etched channels and allows unstimulated zones to be treated. The main advantage of foam diversion is fast and efficient cleanup, which is especially important for depleted formations.Highly retarded emulsified acid helps create wormholes while treating long intervals with low pumping rate through coiled tubing (CT).CT placement with pumping foam diverter through CT and HCl through CT - Tubing annulus simultaneously to block known thief zones.
Up to date 3 stimulation treatments were successfully performed with average incremental gas production of 61% that could not be achieved before on this field. A combination of all solutions and technologies mentioned above allowed to address all challenges related to matrix acidizing on OOGCF field.
Application of Novel Technologies Helps Unlocking Deep Omani Gas
Authors: Briner Andreas , Curtino Joe , Al-Siyabi Hisham , Judd Tobias 
Published: June 2014

Abstract
In 2009 Petroleum Development Oman LLC (PDO) started an ambitious tight and deep gas exploration programme exploring for previously untapped reservoirs. The exploration strategy is focusing on both conventional tight gas plays as well as deep unconventional gas resources. These resources are typically in previously undrilled formations at great depths, with high temperatures and unknown pressure regimes, and uncertain fluid fill and composition. The unique geological properties of this type of reservoir require different strategies and technology deployment in order to make them viable and sustainable.
With unique geomechanical, reservoir, and geological properties, some of the large gas-bearing prospects within the Fahud Basin in the Sultanate of Oman require innovative drilling and completion practices. A revised drilling and completion workflow, with specific technology deployment and operational flexibility, has been developed in order to account for such reservoir complexity. This workflow includes the incorporation of rock strength acquisition and stress state of the reservoir prior to completion, in order to identify targets for hydraulic fracturing and quantify hydraulic fracturing performance versus reservoir deliverability. The unparalled challenges encountered whilst exploring for these resources required resolving to new technologies from outside the region and adapting them to local conditions.
This paper demonstrates the need of integrating various unconventional data sources to enhance the chance of successful reservoir characterization that leads to better understanding of presence of hydrocarbons and reservoir quality. It will also show that classical evaluation methods fail and will not lead to unambiguous interpretations. Recent experience has shown that several independent data sources need to be applied to confidently evaluate well results.
The successful application of a technology plan covering aspects of geomechanics, well completions, perforation and formation breakdown, hydraulic fracture placement and treatment yielded positive results that will be of interest to other regional operators facing similar challenges.
Correlation between Rock Permeability and Formation Resistivity Factor-A Rigorous and Theoretical Derivation
Authors: Ling Kegang 
Published: June 2014

Abstract
Rock permeability is one of most important rock properties for fluid flow in reservoir. According to Darcy’s law flow rate is proportional to permeability holding other variables constant. The methods to get permeability include direct core measurement, well test interpretation, estimating from nuclear magnetic resonance (NMR) logs, and calculating from other properties such as porosity using correlations. It is noted that these methods have their own limitations. Core measurement is expensive, time consuming and limited by core availability. NMR logs are high cost. Correlations are often obtained from scatter data point thus their reliabilities cannot be guaranteed. Therefore new method needs to be found to get permeability.
Starting from multiple-capillary tubes concept, we derived a rigorous relationship between permeability and formation resistivity factor. Through this correlation permeability can be calculated from known formation resistivity factor or vice versa. Since formation resistivity factor is often obtained from lab experiment, the new correlation provided an important supplement in permeability estimation without additional cost. In other words, if permeability is known, the new correlation can be used to verify the formation resistivity factor measured from lab experiment, again, without adding cost. The new correlation also provides a unique approach to quantify the radius of capillary tube, which is not available in the literature before this study.
Validation of Surface and Shallow Microseismic Array for Deep Reservoir Monitoring
Authors: Rosca Anca , Maisons Christophe 
Published: June 2014

Abstract
Monitoring reservoir stimulation operations provides data for predicting production performance and for reservoir characterization but also, potentially, for compliance with local regulations. With improved drilling and completion technology the depth of the unconventional reservoirs produced increases and the options for deploying cost–effective microseismic monitoring equipment become limited. The monitoring technology has to adapt by optimizing acquisition geometry and data processing as well as the procedures that demonstrate the validity of the results. A practical solution for microseismic monitoring of stimulation operations in an unconventional reservoir under development is a surface or shallow distributed array. We are analyzing three such datasets together with complementary deep borehole sensor datasets to understand how to predict and validate the expected performance of distributed surface and shallow arrays. The surface recorded data is processed by stacking and event detection and location are accepted based on statistical criteria. This catalog of events is compared to the one obtained from borehole array where waveforms can be analyzed individually in order to validate the quality of event analysis.
Decision Criteria for Climate Projects
Authors: Osmundsen Petter , Emhjellen Magne 
Published: June 2014

Summary
This article analyzes commercial decision criteria for climate projects. The latter will normally be executed by private players, for whom decision criteria developed from a commercial perspective are important. But such criteria are also important for the government in calculating the size of subsidies required for various measures. A ranking of different solutions in a socioeconomic context must rest on calculations made from a commercial perspective. Examples of the subjects covered include the calculation of abatement unit costs and cost estimating for climate projects. The carbon-capture project at the Kårstø gas-fired power station in southwest Norway is used as a case throughout the analysis.
Gel Dehydration by Spontaneous Imbibition of Brine From Aged Polymer Gel
Authors: Brattekås B. , Haugen Å. , Graue A. , Seright R. S. 
Published: June 2014

Summary
This work investigates dehydration of polymer gel by capillary imbibition of water bound in gel into a strongly water-wet matrix. Polymer gel is a crosslinked-polymer solution of high water content, where water can leave the gel and propagate through porous media, whereas the large 3D polymer-gel structures cannot. In fractured reservoirs, polymer gel can be used for conformance control by reducing fracture conductivity. Dehydration of polymer gel by spontaneous imbibition (SI) contributes to shrinkage of the gel, which may open parts of the initially gel-filled fracture to flow and significantly reduce the pressure resistance of the gel treatment. SI of water bound in aged Cr(III)-acetate-hydrolized-polyacrcylamide (HPAM) gel was observed and quantified. Oil-saturated chalk-core plugs were submerged in gel, and the rate of SI was measured. Two boundary conditions were tested: all faces open (AFO) and two-end-open oil-water (TEO-OW), where one end was in contact with the imbibing fluid (gel or brine) and the other was in contact with oil. The rate of SI was significantly slower in gel compared with brine, and was highly sensitive to the ratio of matrix volume to surface open to flow, decreasing with increasing ratios. The presence of a dehydrated gel layer on the core surface lowered the rate of imbibition; continuous loss of water to the core increased the gel layer concentration and thus the barrier to flow between the core and fresh gel. Severe gel dehydration and shrinkage up to 99% were observed in the experiments, suggesting that gel treatments may lose efficiency over time in field applications where a potential for SI exists. The implications of gel dehydration by SI, and its relevance in field applications, are discussed for both gel and gelant field treatments.
Simulation of Fracturing Induced Formation Damage and Gas Production from Fractured Wells in Tight Gas Reservoirs
Authors: Ding Y. D. , Langouët H.. , Jeannin L.. 
Published: June 2014

Abstract
Fracturing fluid may jeopardize the production of hydraulically fractured tight gas formations. Ascapillary forces are acting stronger in low permeable formation, the invaded fracturing fluid is harder to be removed. The increase of water saturation around the fractured well affects the mobility of the gas phase, particularly in tight formations where the gas relative permeability declines stronglywhen water saturation increases. This damage might greatly reduce the gas production in a very long cleanup period. This paper presents numerical simulation techniques to account for formation damage with both a near-well model and a full-field model for fractured wells in tight formations and to integrate damage effects in a full-field reservoir model through an efficient coupled modelling.
Wellbore Pressure Surges Produced by Pipe Movement
Authors: Burkhardt J.A. 
Published: June 2014

Abstract
Field measurements and theoretical studies have been made of pressure surges-momentary variations in fluid pressure-produced by movement of pipe in mud filled boreholes. Pressure measurements were recorded by five pressure gauges located at various positions in the borehole. An important positive pressure peak was found to occur as the casing moved with maximum velocity. Important negative peaks were found as the casing was lifted from the slips and as brakes were applied to stop pipe movement. A rigorously formulated theory has successfully predicted the sequence and magnitudes of these positive and negative surges and has established a basis for understanding how they occur.
Both the measurements and theory indicate that the most important pressure surge is usually due to viscous drag of the flowing mud. The theory of viscous-drag pressure surges has been approximated by simplified graphs and calculation procedures to facilitate ready use in field operations. Comparison of measured results with those predicted by the simplified theory shows that the magnitude of this surge can be predicted accurately.

Introduction
It is widely recognized that raising or lowering pipe in a fluid-filled borehole produces momentary variations in fluid pressure, commonly called pressure surges. Both negative (or "swabbing") surges and positive (or "fracturing") surges may occur. In 1934, Cannon measured the negative surges and showed that they could be large enough to cause flow of formation fluids into the wellbore and, in extreme cases, lead to blowout conditions. Later, Goins measured the positive surges associated with lowering pipe. His results and subsequent field operations strikingly demonstrated that pressure surges could be an important factor in some cases of lost returns. In addition, although the evidence is less clear than in the case of blowouts and lost returns, other investigators feel that pressure surges probably play a part in many instances of minor gas cutting, salt-water flow and other hole trouble.
The importance of pressure surges in drilling operations led naturally to attempts to explain the physical causes, nature and magnitude of the surges. Cardwell was the first to publish a theory which allowed the quantitative prediction of momentary pressure variations. He assumed that the drilling fluid was a 300-cp Newtonian fluid in turbulent flow. Most field muds have a considerably lower viscosity and are generally believed to be Bingham plastic in nature a However, Cardwell's results were useful because they were presented in a form convenient for field use and, in some cases, gave a reasonably accurate predicted value for the maximum pressure surge.
Experimental Investigation of Fracturing-Fluid Migration Caused by Spontaneous Imbibition in Fractured Low-Permeability Sands
Authors: Dutta R.. , Lee C.-H.. -H. , Odumabo S.. , Ye P.. , Walker S.C.. C. , Karpyn Z.T.. T. , Ayala H. L.F.. F. 
Published: June 2014

SummaryDuring hydraulic-fracturing operations in low-permeability formations, spontaneous imbibition of fracturing fluid into the rock matrix is believed to have a significant impact on the retention of water-based fracturing fluids in the neighborhood of the induced fracture. This may affect the post-fracturing productivity of the well. However, there is lack of direct experimental and visual evidence of the extent of fluid retention, evolution of the resulting imbibing-fluid front, and how they relate to potential productivity hindrance. In this paper, laboratory experiments have been carefully designed to represent the vicinity of a hydraulic fracture. The evolution of fracturing fluid leakoff is monitored as a function of space and time by use of X-ray computed tomography (CT). The X-ray CT imaging technique allows us to map saturations at controlled time intervals to monitor the migration of fracturing fluid into the reservoir formation. It is generally expected for low-permeability formations (5 to 10 md) to show strong capillary forces because of their small characteristic pore radii, but this driving mechanism is in competition with the low permeability and spatial heterogeneities found in low-permeability sands. The relevance of capillarity as a driver of fluid migration and retention in a low-permeability sand sample is interpreted visually and quantified and compared with high-permeability Berea sandstone in our experiments. It is seen that although low-permeability sands are subject to strong capillary forces, the effect can be suppressed by the low permeability of the formation and the heterogeneous nature of the sample. Nevertheless, saturation values attained as a result of spontaneous imbibition are comparable with those obtained for high-permeability samples. Leakoff of fracturing fluids during the shut-in period of a well can result in delayed gas flowback and can hinder gas production. Results from this investigation are expected to provide fundamental insight regarding critical variables affecting the retention and migration of water-based fracturing fluids in the neighborhood of hydraulic fractures, and consequently affecting the post-fracturing productivity of the well.
Lessons Learned From Steam Generation: Novel Chemical Control And Integrity Management During The Commissioning And Start-up Of The Schoonebeek Facilities
Authors: Shepherd Andrew G. , Jonker Edwin , Bayens Peter 
Published: June 2014

Abstract
This paper describes the chemical control and integrity management steps taken during the commissioning and start-up of the Combined Heat and Power plant (CHP) of a large field redevelopment. The chemical controls were carried out using a combination of new and established chemistries in oxygen scavenging, corrosion inhibition and scale inhibition. Carefully designed passivation and slugdosing, in addition to a clear and robust sampling and analysis plan, had a direct impact on the development of these operations. The lessons learned of two boiler systems are discussed together with the improvements implemented to achieve fit for purpose steam generation. This has included for instance, particular attention on the monitoring of boiler feed water quality and use of hydrogen meters. Furthermore magnetite formation was established for two boiler systems. This was confirmed by pH trends in the high pressure drums, sample appearance, hydrogen measurements and analysis of solids taken during various stages of monitoring. The results suggest that magnetite formation occurred at conditions different to what is the established rule of thumb during high pressure start-ups, e.g. 30 bar. It is speculated that such behavior was influenced by the chemical control selected. Key performance indicators (e.g. phosphate operational window) as well as automated chemical dosing is allowing good integrity control of the steam generation system as the facility migrates into steady state operation.