bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Choice of a ‘Best’ Assisted History Matching Algorithm
Authors: Hanea R. G. , Przybysz-Jarnut J. K. , Krymskaya M. V. , Heemink A. W. , Jansen J. D. 
Published: July 2010

Abstract
Computer-assisted history matching is the act of systematically adjusting a ‘prior’ reservoir model using measured data until its simulated production response closely reproduces the past behavior of the reservoir. Thereafter, the updated, ‘posterior’, model is expected to predict future reservoir behavior with a higher degree of confidence, particularly if the adjustments are constrained by known geological properties of the reservoir. The accuracy of the history matching process depends on the quality of the prior reservoir model and the quality and quantity of measured data, typically production data (pressures and flow rates at well locations). The uncertainties in the prior reservoir model and in the measurements have a strong effect on the uncertainty in the parameter values of the posterior model, and thus on the predictions to be made with that model. A common way to include these uncertainties is through the specification of spatial covariance matrices for prior reservoir parameters and measurement errors respectively. Here we consider two assisted history matching techniques that use such a covariance-based uncertainty description, the representer method and the ensemble Kalman filter, both originating from oceanography. In their most simple form, used for state estimation in linear systems, they lead to identical estimates. However, when applied to nonlinear reservoir models their results differ. We compare the quality of the parameter estimates using both methods for a synthetic ‘twin experiment’ where the true parameter field is known allowing for comparison with the estimates. We consider simple two-dimensional water flooding cases with ‘true’ reservoir permeabilities represented by either a Gaussian random field or a channelized geology. The corresponding spatial covariance matrices are obtained with the aid of geostatistical ensembles of prior models, conditioned on known permeability values in the wells. We compare the quality of the history match, the permeability estimates, and the predicted water rates after the history matching period using both methods, starting from two different priors for each of the methods. We conclude, for the cases considered in this study, 1) that because of the limited information present in production data assessing the ‘best’ method to reconstruct the parameter field is not possible; 2) that from the point of view of prediction after the assimilation period, the ‘best’ assisted history matching method appeared to be the representer method, but that this might be related to the particular implementation of the methods in our study, and 3) that further research is required into the effect of treating nonlinearities in the system and output equations, and especially into the effect of iterative procedures.
Achieving Extending Squeeze Life in Challenging Wells - A Non Conventional Approach
Authors: Sorhaug Eyvind , Jordan Myles M. , Marlow David , Stalker Robert , Graham Gordon 
Published: July 2010

Abstract
Over the past 10 years significant improvements in "green" scale inhibitor chemistries have led to considerably increased use in certain regions, notably the Norwegian sector of the North Sea. However, the use of these more environmentally acceptable products can be at the cost of optimum performance. This was the case for the Varg field: an extensive Best-In-Class re-selection of available yellow / green polymeric inhibitors failed to achieve the required improvement in lifetimes. Modelling work conducted for one of the wells had also shown that one of the primary causes of the poor lifetimes was the lack of effective placement of the treatment chemical in the water-producing zones.1 More recent experimental work to be described in this paper has demonstrated that the scaling challenges on this field could be mitigated in part by adopting the less environmentally friendly, but better retaining, ‘red’ phosphonate chemical. Comparison of the predicted inhibitor return profile using laboratory derived data with the subsequent field return showed very good correlation in a well with no placement challenge. In a manner analogous to the polymer-based chemistries,1 application of the phosphonate inhibitor in a well with known placement issues gave less impressive return lifetimes. However the better retention properties meant that the treatment lifetimes remained acceptable despite the poor placement. When the placement issues were taken into account, the previously derived isotherm proved very effective at simulating the field case in this more challenging well. This paper therefore describes an alternative, more rigorous approach to simulating treatments in challenging wells rather than using history matched averaged field return isotherms. The paper then shows the impact on optimisation of future treatments when the different approaches are examined. This work therefore expands considerably on that previously described in SPE 114077.
The Influence of CO2 Solubility in Brine on Simulation of CO2 Injection into Water Flooded Reservoir and CO2 WAG
Authors: Yan Wei , Stenby Erling H. 
Published: July 2010

AbstractInjection of CO2 into depleted oil reservoirs is not only a traditional way to enhance oil recovery but also a relatively cheaper way to sequester CO2 underground since the increased oil production can offset some sequestration cost. CO2 injection process is often applied to water flooded reservoirs and in many situations alternating injection of water and CO2 is required to stabilize the injection front. Both scenarios involve a large amount of water, making CO2 solubility in brine, which is around ten times higher than methane solubility, a non-negligible factor in the relevant reservoir simulations. In our previous study, a 1-D slimtube simulator, which rigorously accounts for both CO2 solubility in brine and water content in hydrocarbon phases using the Peng-Robinson EoS modified by Soreide and Whitson, has been used to investigate the influence of CO2 solubility on the simulation of continuous CO2 flooding with uniform initial water saturation. As a follow-up of the previous study, this study extends the investigation to two more realistic scenarios (1) CO2 injection into water flooded reservoir and (2) water-alternating-gas (WAG) injection with CO2 as the injection gas. A series of 1-D simulations were made for seven oil samples within a wide range of temperature, pressure and salinity. The results were analyzed in terms of the change in oil recovery due to different phase equilibrium descriptions, the delay in breakthrough and the CO2 lost to the aqueous phase. The influence of different factors, including temperature, pressure, salinity, water injection pore volume, WAG ratio and CO2 slug size, on the simulation results was also discussed. In addition, the results for CO2 injection into water flooded reservoirs were also compared with those from the previous study.
Logging under Harsh Conditions with New Shuttle-Deployed Memory Tools and Impact on Log Quality, Time and Costs
Authors: Miranda Luis Javier , Angel Franklyn 
Published: July 2010

Abstract
Operational conditions in certain fields can cause various difficulties during logging operations. When such situations occur, we usually opt for logging-while-drilling (LWD) tools. In this paper, we present field applications and advantages of a new generation of tools called shuttle-deployed memory (SDM) tools. Because they can operate under critical borehole conditions and highly deviated wells, SDM tools offer a viable alternative to LWD.
We successfully applied this technology to acquire well-log data in two fields of clastic and carbonate reservoirs in the Barinas-Apure Basin, Southwest Venezuela. In this area, conditioning the hole is a required procedure before running logging tools; therefore, the logging system's capacity to get information while conditioning the borehole favored its application when logging under harsh conditions. We show three cases considering wells with angle of deviation up to 40º, dog leg severity up to 4º/100 ft, and several washout and unsteady zones. A comparison with resistivity measurements obtained using an LWD tool is also included in one of the cases, illustrating remarkable improvements in log quality. We also used the acquired information as an input for petrophysical assessment. The results satisfactorily compared against neighbor wells with data obtained from conventional wireline logging tools and rock-core measurements. Likewise, a detailed analysis of time and cost describes the impact of the application of this type of technology on operations in Guafita and La Victoria Fields in Venezuela.
We conclusively found that the application of SDM tools for formation evaluation data acquisition reduces logging time by 62% and logging costs up to 44% in these fields. In addition, we obtained reliable well-log information with significant improvements in log quality. More important, the application of SDM tools allowed us to bypass the limitations in terms of variety and quantity for logs that were commonly acquired with LWD tools.
Polymer Flooding – Flow Properties in Porous Media Versus Rheological Parameters
Authors: Stavland A. , Jonsbråten H. C. , Lohne A. , Moen A. , Giske N. H. 
Published: July 2010

Abstract
Mobility reduction is one of the critical parameters in polymer flooding. The EOR polymers have shear thinning bulk rheology, while core flood experiments with hydrolysed polyacrylamide (HPAM) in this paper show four different viscosity regimes. Through a systematic work, in which the molecular weight and degree of hydrolysis as well as the permeability and brine salinity were varied, the apparent viscosity was well-matched with theoretical models. The following four viscosity regimes were identified: (i) At low shear rates, the apparent Newtonian viscosity is less than the bulk viscosity; this effect is because of the inaccessible pore volume (IPV) with the polymer not entering the entire pore space. (ii) Shear thinning behaviour which is controlled by the polymers relaxation time, λ1. (iii) At high shear rates, the apparent viscosity increases by increasing the shear rate caused by elongation whose onset is controlled by a critical shear rate which depends on the relaxation time. (iv) At very high shear rates, the apparent viscosity decreases by increasing the shear rate because of mechanical polymer degradation caused by polymer rupture.
The controlling parameter is the bulk relaxation time for the polymer. The critical shear rates for elongation and shear degradation increase when the effective molecular weight decreases. Typical injection shear rates in offshore matrix reservoirs exceed the critical shear rate for elongation and shear degradation. Consequently, high molecular weight HPAM will either have poor injectivity or cause fracturing. For injection into fractured wells, the shear rate is substantially reduced and the shear degradation can be avoided. Acrylamido-Propyl-Sulfonate (AMPS) co-polymers have similar apparent viscosity versus shear rate as the HPAM. However, the AMPS co-polymers seem to tolerate higher shear rates before degradation sets in.
For comparison, core flood experiments with Xanthan have been performed. This polymer was shear stable and the shear thinning apparent viscosity was similar to the bulk viscosity.
The polymers reduced the permeability and the permeability reduction is understood by the polymer size, i.e., the permeability reduction increases by increasing the molecular weight.
The Development of a Water-Free and Light Oil-Soluble Scale Squeeze Inhibitor Meeting Environmental Requirements
Authors: Guan Hua , Grinrod Anders , Rohde Hans C 
Published: July 2010

Abstract
The major technical drive for introducing oil-soluble scale inhibitors is to overcome the potential oil production decline caused by conventional aqueous-based scale-inhibitor squeeze packages in situations where relative permeability effects, water blocking, fluid lifting or deep penetration into the near well formation are of major concern. The particular requirement for a true oil-soluble scale inhibitor in a low-pressure reservoir with wells having lifting problems is that the package density needs to be lower than that of water. Additionally in certain geographical regions like Norway, the environmental regulations are very tight.
This paper illustrates the development of a true oil-soluble scale-inhibitor package with zero water content. The product is light with a density of much less than 1 g/cm3 and its environmental category in Norway is yellow. The successful product is the result of numerous formulation trials. Details of chemistry selection and the formulation development will be discussed in the paper. Following the success in formulation, the product has undergone stability, solubility and core flood testing to further evaluate its suitability as a squeeze inhibitor. The core flood results show an extended scale inhibitor return during the post flush; the scale inhibitor is still well above MIC (Minimal Inhibitor Concentration) for &gt; 700 pore volume (PV) of post flush. The possible mechanism for this squeeze lifetime extension is discussed in the paper. No formation damage was observed during the reservoir condition multiphase core flood indicating the nondamaging nature of the true oil-soluble product. Based on this successful development, a field trial is planned.
This paper discloses the development of a true oil-soluble scale-inhibitor formula that is water free, low density and in the yellow environmental category, which can be applied downhole as scale squeeze inhibitor providing a prolonged squeeze lifetime.
Emergence of Diamond-like Carbon Technology: One Step Closer to OCTG Corrosion Prevention
Authors: Gore Mark J. , Boardman Bill 
Published: July 2010

Abstract
Careful consideration of corrosion management during component manufacture is critical to protect assets over their useful field life. Recently, a new technology was introduced that can delay or mitigate the onset of corrosion on oil country tubular goods (OCTG) used in oil and gas production operations. The innovative method produces and applies a layered diamond- like-carbon (DLC) to the internal surface of OCTG tubulars by using a plasma enhanced chemical vapor deposition (PECVD) process. The technique makes use of the hollow cathode effect (HCE) to achieve a high deposition rate and a high ion bombardment rate. Initially developed for the coating of internal surfaces of piping with length:diameter aspect ratios less than 20, the process has recently been extended to high aspect ratio piping including OCTG. Its ion bombardment produces a dense barrier of a hard, wear and corrosion resistant DLC surface coating. The improvement in deposition rate and increase in thickness compared to earlier plasma coatings has enabled new applications such as corrosion and abrasion protection. Corrosion resistance is demonstrated based on exposure to HCl and NaCl environments. Mechanical properties include high hardness, high adhesion, and good wear resistance.
The new technology enables a widespread use of DLC based coating and has significant potential to increase component life in applications where the internal surface of pipes are exposed to corrosive and abrasive environments especially in the oil and gas industry. The described surface treatment provides a new alternative to traditional polymer type coatings and/or increased alloy contents.
The Influence of Maleic Acid Co-polymers on the Growth and Microstructure of Calcite Scale
Authors: Senthilmurugan B. , Ghosh B. , Graham G. M. , Kundu S. S. 
Published: July 2010

Abstract
Additive-mediated crystal growth has been a large area of scientific research over many generations. In oil and gas production crystal growth modifiers (scale inhibitors) are used routinely, although their impact on the structure and morphology of the scale is often overlooked. This work presents results for the inhibition of calcite using specially prepared maleic acid – acrylic acid and maleic acid – acrylamide co-polymers. Performance tests show that the inhibitors provide effective performance against CaCO3 in both static and dynamic conditions. Additive-mediated crystallisation was then progressed at concentrations below the MIC’s. The results show significant changes in the microstructure and morphology of the crystals formed, from typical calcite rhombs in the absence of additives towards needles and aragonite structures as well the formation of almost perfectly formed "micro-rosettes". The trends in the microstructure are tracked as a function of temperature and chemical concentration and are related to the inhibitors ability to influence different crystal growth surfaces under different conditions. More significantly, dramatic differences are recorded under dynamic and static test conditions, indicating that the structures which lead to adherence and blocking of pipework during flow may be different than those which dominate under bulk conditions. The indication is that the most effective inhibitors are those which inhibit crystal morphologies which lend themselves towards adhesion and growth from metal surfaces.
The synthesis and characterisation of the polymers together with calcium carbonate inhibition performance results and crystal microstructures formed in static and dynamic conditions are presented, together with conclusions on their importance when attempting to inhibit scale formation on pipeline walls in dynamic oil production systems. Previous published works in this area will be included to support the conclusions made.
Proactive Well Placement Integrated into a Systematical Approach Enhances Productivity in a Complex Offshore Field, Bohai Bay
Authors: Deng Jian Ming , Liu Peng , Zhao Yong Sheng , Tan Lv , Li Gang , Yang Bin , Xian Cheng Gang , Wang Ruo , Parlindungan M. H. 
Published: July 2010

Abstract
Horizontal wells are being a common practice in offshore field development in Bohai Bay recently. Maintaining well trajectory in sweep spot while drilling is one of the key factors to optimize productivity of horizontal wells. To achieve this, great challenges are often faced in Bohai bay area including bias between the existing model and the actual, including microstructure and fluvial channels, sand-shale inter-bedding, strong permeability heterogeneities, complex special distribution of reservoir fluids (gas cap, bottom water or edge water) and relatively thin hydrocarbon pays. Therefore, the ability to update reservoir model in timely manner and to proactively adjust well trajectory in real time are required.
This paper presents a successful case in Bohai Bay by applying proactive well placement technology into an integrated approach to achieve very promising productivity than the initial prediction from two appraisal wells. This approach includes integrated reservoir study, operation optimization from drilling to completion, proactive well placement, real time interpretation, model updating and decision making. During integrated reservoir study, selected parameters and criteria to plan locations and trajectory of horizontal wells were derived from thorough rock physics and petrophysics studies. Detail geomechanical analysis was applied to optimize drilling and completion strategy. Proactive well placement technology - characterized by up to 15ft depth of investigation, directional measurements, 2D mapping of boundary/contact and 3D visualization was applied to optimize the placement of well trajectory in real time; which was also used to update reservoir model while drilling and close the gap between pre-drill existing model and real time interpretation. As the result, productions of the drilled two pilot horizontal wells are greatly exceeding the initial prediction. This proven approach can be applied to other planed wells in this field and other similar fields in Bohai Bay.
Measurement and Analytical Approach for Geological Core Investigation using Photogrammetic Methods
Authors: Sun Pinghe , Wu Xiaoming , Deng Mike 
Published: July 2010

Abstract
Formation micro imager is applied in geological investigation of borehole which can provid much more properties than core sample collection. In this paper, the photogrammetic method is discussed during the lab test based on images. Photogrammetric technology is the technique of measuring objects (2D or 3D) from images. During the test process, 35 printed target points are set on the plastic clay which is adhere to the simulation borehole surface and taking photos from different locations to get the points’ information. The software of PhotoModeler is used to analyse these photos with fixing the origin point, the direction of 3D coordinate and the distance between any 2 target points. All these points (x, y, z) are obtained in this test by focus length of 18mm, 35mm and 55mm. There are differences between the 3 focus lengths for the same point's x, y and z. The results show that the parameters of RMS (Root Mean Square) marking residual and tightness have negative effection on the precision. We can identify the physical properties of a borehole surface (borehole breakout, fracture, et al.) accurately by this technology to improve exploration and production results utilizing advanced borehole. It also can reduce coring and associated drilling costs (partial core replacement).
Investigation and Application of Multistage Hydrajet-Fracturing in Oil and Gas Well Stimulation in China
Authors: Li Gensheng , Huang Zhongwei , Tian Shouceng , Niu Jilei , Qu Hai , Sheng Mao 
Published: July 2010

Abstract
Multistage hydrajet-fracturing combines abrasive jet perforating and hydraulic fracturing to perform separate, sequential fracture stimulations without mechanical packers. It can reasonably place fractures according to geological condition, and then accurately treat them. Without packer, it uses dynamic isolation to seal flow into target, saving operating time and lowering operating risk. Therefore, the process not only adapts to stimulate open hole, but effectively treats liner or cased completions.
The mechanisms and fluid dynamics of multistage hydrajet-fracturing technology are investigated with numerical simulation and laboratory experiments. More than 30 oil and gas wells have been successfully treated using this technology since 2007. On average, three hydraulic fractures with total 120m3 proppants were placed at strategically selected locations in well, typically several hundred meters apart without sealing equipments. The deepest treatment in oil well 203-19 in Zhongyuan oilfield, using tubing string, was 3692m, and surface pressure reached 88MPa. Significant stimulation results were achieved in these wells. For example, production increased by more than 50 times after stimulation to the gas well XS311H in Sichuan oilfield. The oil well 92-2 in the Zhongyuan oilfield, which had been a dead horizontal well, has been revived using this technology with average oil production of 15 tons per day.
Multistage hydrajet-fracturing stimulation shows promising feature for horizontal, vertical, deviated, and even multilateral wells.