bluuebunny/crossref_metadata_2025_split huggingface dataset:
FAWAG: A Breakthrough for EOR in the North Sea
Authors: Aarra M. G. , Skauge A. , Martinsen H. A. 
Published: December 2007

Abstract
The application of FAWAG (Foam Assisted WAG) on the Western fault block at the Snorre field has qualified foam as a gas mobility agent for North Sea reservoirs. Results from the foam mobility control trial on WFB at Snorre, well pair P32-P39, were conclusive. The results show that gas breakthrough was delayed and the Gas-Oil-Ratio (GOR) was considerable lowered compared to pre-foam gas injection cycles. Large volumes of gas have been stored in the reservoir. Analysis has shown that gas material balance, decline analysis, and simulations all give consistent results. The expenses for FAWAG on Western Fault block (WFB) was 1M USD, and additional oil recovery value is estimated to ~ 25-40M USD at current oil prices.
The FAWAG on WFB has been history matched using a commercial foam simulator. Assuming the same foam properties as in the history match, simulations have been performed to evaluate further potential for FAWAG on WFB of the Snorre field and on the Visund field. These predictions show a significant potential for increased oil production and storage of gas: –Simulations of a 2nd FAWAG injection in the same well pair, P32-P39, estimate an increased gas storage at the same level as for the 1st FAWAG injection, and indicate a maximum increased oil recovery potential in the range of ~ 400 000 Sm3.–The potential for FAWAG in a neighboring well pair in WFB indicate an increased gas storage of ~ 106 MSm3 and a maximum increased oil recovery potential up to ~ 650 000 Sm3.–The potential for FAWAG injection in the N1 segment of the Visund field suggest an increased gas storage potential of 191 MSm3 and an increased oil recovery potential of 217 000 Sm3, when injecting 400 tons of 38% active surfactant.
Artificial Neural Network Architectures for Predicting Two-Phase and Three-Phase Relative Permeability Characteristics
Authors: Silpngarmlers N. , Ertekin T. 
Published: December 2007

Abstract
Laboratory determination of relative permeability characteristics is labor intensive and can be complicated. Empirical models to predict relative permeabilities based on rock and fluid properties have experienced relatively limited success. Hence, alternate methodologies for accurate determination of relative permeability characteristics are always desirable.
In this study, two-phase and three-phase relative permeability predictors are developed using backpropagation networks. In this category of networks, information is passed from input layer to output layer, and calculated errors are propagated back to adjust the connection weights in a sequential manner to improve the predictive capabilities of the models. In the development of the models, experimental relative permeability data along with some commonly reported rock and fluid properties obtained from the literature are used during the training stage, while some other data sets are preserved to test the prediction ability of the models. The two-phase relative permeability models are found to perform in a satisfactory manner within a wide spectrum of basic rock and fluid properties. Similarly, three-phase relative permeability models are observed to have good predictive capability in accurately producing the missing entries of three-phase data sets for a series of isoperms, and in constructing the missing isoperms for a system under consideration. Furthermore, they are found to be capable of effectively predicting the three-phase relative permeability values at various saturation combinations for systems with different rock and fluid properties.
Riserless Subsea Completion with Disappearing Plug Technology
Authors: Stair Craig D. , Stuckey Joe T. 
Published: December 2007

Abstract
The installation of a subsea tree from a floating drilling rig is one of the most complex and time-consuming portions of a deepwater subsea well completion. Removing subsea tree installation from the rig "critical path" would yield a step-change reduction in the time and cost to complete a subsea well.
Disappearing plug technology holds the key to achieving this improvement. Regulations (and good practice) dictate the use of a plug set in the tubing hanger of a completed well to provide a barrier to well flow. Until recently, most subsea trees were installed from the drilling rig on a completion riser, after the BOP stack and marine riser were removed. The completion riser also provided the conduit to remove the tubing hanger plug. "Disappearing plug" technology eliminates the need for the completion riser and drilling rig during subsea tree installation because it acts as a well barrier, performing the same function as the tubing hanger plug, until it is opened remotely from the host facility.
This paper discusses the application of disappearing plug technology to a subsea project, the synergies created between downhole completion operations and subsea installation activities, and the resultant time and cost savings.
On the Relationship between Resistivity and Permeability Anisotropy
Authors: Georgi D. , Bespalov A. , Tabarovsky L. , Schoen J. 
Published: December 2007

Abstract
Measurement of resistivity anisotropy is critical to reserve estimation and permeability anisotropy determination is key to efficient hydrocarbon exploitation. It is now possible to measure resistivity anisotropy with new wireline, multi-component induction hardware. However, it is difficult to directly measure or determine permeability anisotropy. Thus, it would be beneficial to be able to relate resistivity and permeability anisotropy and predict kv:kh from Rh:Rv (where kv and kh are the vertical and horizontal permeabilities, and Rv and Rh are the vertical and horizontal components of formation resistivity).
We know that both resistivity and permeability anisotropy are scale dependent. In our study, we define three scales for formation anisotropy properties: The Micro-scale relates directly to the properties of individual components (e.g., sand and shale). The Macro-scale is an intermediate scale defined by the vertical resolution of the measurement tools. Most logging tools are not capable of resolving the individual lamina in laminated sand-shale sequences. In this case, the "macroscopic anisotropy" can be described by the well-known rules for conductors connected in parallel and/or in series. At the Reservoir-scale, anisotropy is governed by interconnected channels formed by gaps in the relatively impermeable shale layers.
We have developed a numerical simulator that allows us to model at all scales the anisotropy for resistivity and permeability for arbitrary three-dimensional, periodic structures. The simulation results have been verified with known analytical solutions. With this model we have explored reservoir-scale anisotropy as a function of the lateral extent of the shales and sands. By varying the thickness of the sands and shales, we investigated the effect of net-to-gross on the electrical and permeability anisotropy.
From our studies we conclude that the relationship between resistivity and permeability anisotropy is not trivial. On the smaller scales it is controlled by the spatial distribution of the pore-space properties and on the larger reservoir scales by the spatial distribution of the sand bodies and gaps in the shale barriers.
We show both numerically and theoretically for 2D structures that resistivity and permeability anisotropy are identical for cells with inverse property contrasts. This implies that fluid and current flow anisotropy are equal. However, this does not hold for every 3D geometry and in general there is no correlation between permeability and resistivity anisotropy on the macroscopic or reservoir scale for laminated sand-shale systems.
Optimization of Microbial Flooding in Carbonate Reservoirs
Authors: Almehaideb Reyadh , Zekri Abdulrazag Y. 
Published: December 2007

Abstract
Up to date, several investigators have studied the possibility of using microorganism in improving oil recovery, but little work has been reported regarding optimization of the process. In the laboratory, bacteria have been shown to produce chemicals such as surfactant, acids, solvents, polymers, and gases (mainly CO2) that can significantly contribute to improving displacement and sweep efficiency. Some of these microorganisms can withstand the harsh environment of the oil field and grow at a substantial rate feeding on the organic matter and crude oil itself, thus leading to improvement of oil recovery. Moreover, the MEOR process is friendly to the environment. Several field trials have been reported that showed the potential of bacterial enhanced oil recovery (BEOR) in improving oil recovery.
Because these microorganisms are living organism and their behavior is difficult to predict, therefore no attempt has been made to study the parameters that control the process performance. This has become the main objective of this work. In this work, we investigate the field parameters that affect the design a new process of Microbial Enhanced Oil Recovery in order to achieve optimum oil recovery. In order to reach this goal, the reservoir engineering factors that affect the recovery efficiency are defined first. These field parameters considered the most relevant and chosen for this study are the injected bacteria concentration, the adaptation time, the optimum slug size of bacteria solution, and the process application time. The capability of the microbes to transmit through a heterogeneous system and in long cores, and the effect of bacteria on rock wettability are also investigated.
Application of a New Crosslinked Polymer Displacement Technology at Bo-19 Block in Gudao Oilfield
Authors: Song Wanchao , Zeng Xianxiang , Yao Haixia , Li Jiyong , Lv Xihui , Tian Yuqin , Guo Yanjun 
Published: December 2007

Abstract
A new EOR method of Crosslinked polymer displacement technology is introduced in this paper. The crosslinked system is based on the reaction of Cr(III) in crosslinker with hydrolysed polyacrylamide(HPAM). After gelation, the system has some character such as good viscoelasticity, good thermal stability, and high salinity resistance. The viscoelasticity of crosslinked system can reach 2–3 times simple polymer solution. As a new system combining profile modification and flooding, it can be applied in high water-cut and severe heterogeneous reservoirs. Because of delayed crosslinking property, it can not only improve profile during injection, but also flow increase volumetric sweep efficiency. Having been injected into reservoir, crosslinking polymer can block and adjust high permeability zones in deep section, and improve sweep volume, and decrease water to oil mobility ration, thereby enhance recovery efficiency.
The pilot is is in BO-19 block in GUDAO oilfield, which is characteristic of positive rhythm deposit, loosed sand cement, high density and high viscosity etc. The reservoir temperature is 73°C, the viscosity of crude oil is 80mPa.s, density is 0.9030g/cm3 at reservoir conditions, permeability is 1000–2000×10−3μm2 and the formation water salinity is 6453mg/L. It has 21 injection wells and 40 production wells, the oil-bearing area is about 2.4km2 and reserve in place is about 737.3×104 tons. From 1999 to 2001, 0.15PV (pore volumes) of crosslinked polymer solution has been injected, and a good effect of increasing oil and decreasing water appears, oil production increases from 201 to 350 tons per
day, composite water cut decreases from 91.3% to 84.6%, cumulative incremental oil reached 5.0×104tons.
Restudy of Main Factors of Effects on ASP Flood and Expansion of Capillary Theory in Heterogeneous Reservoirs
Authors: Hou Jirui , Liu Zhongchun , Yue Xiang'an , Zhang Shufen , Yang Jinzong 
Published: December 2007

Abstract
The demonstration projects of ASP flooding have been implemented in Daqing oil field. With the enlarging of the scope of testing areas, the effects of the scale production resulted from high concentration of alkali (1.2%wt) have been gradually exposed. It resulted in many questions, such as the increase of the resistance of formation's percolation, the decrease of production and the blocking of pumps. All these have become the severe obstructer of the application of ASP flooding.
As to the formation conditions in Daqing oil field, the effects of alkali concentrations on the curling degree of polymer molecules in ASP solution have been studied by using Nanoscope IIIa type AFM in Digital Instruments Company in America. The results show that the chains of polymer molecules spread in liquid phase without alkali, but the chains curl for adding alkali. In the condition of high concentration alkali, the curled chains of polymer molecules are very tight. The polymer molecules do not spread fully, and exist in the state of assembling of many molecules on their sides. Correspondingly, the rheological characteristic of ASP solutions has been studied by using HAAKA apparatus for analyzing rheology. Moreover, the physical simulations of ASP flooding on three-dimensional heterogeneous models and filling sand tubes have been performed. The results show that the ASP solution with a low alkali's concentration and a higher viscoelasticity can get a very high oil recovery by enlarging sweep efficiency and unit displacement efficiency. To heterogeneous reservoir, the viscoelasticity of ASP solution plays a more important role than the ultra low interfacial tension. Else, since the effective distance of action of the surfactant over 60% of ASP cost is very limited in formations, the ultra low interfacial tension is difficult to bring a benefit which it should does. Through a lot of calculations, the revised correlation of capillary number has also been presented in this paper. Finally, through analyzing of the effect of the demonstration project in west of Xing-2 area, the significance of the viscoelasticity has been verified again from the field tests. The feasibility of ASP flooding with low alkali has been determined further, and a new method has been studied for solving alkali scale in ASP flooding in this paper.
Overview of Stimulation Technology for Horizontal Completions without Cemented Casing in the Lateral
Authors: McDaniel B. W. , East Loyd , Hazzard Vance 
Published: December 2007

Abstract
Many horizontal wells have been drilled in low- to moderate-permeability formations and completed in a manner that assumed there would not be a need for a true "stimulation" treatment. This has been a widespread occurrence in both the U.S.A. and Canada, and to a lesser extent for other locations around the globe.
Completing the horizontal section either openhole or with a noncemented liner is economically attractive. However, in many low-permeability reservoirs, and some with moderate-permeability values, production has often been below expectations and sometimes commercially unfeasible, even following efforts to overcome near-wellbore damage problems. This is especially true when considering only completions in reservoirs other than fractured chalks. In more permeable reservoirs, the higher investment costs of underbalanced drilling have often allowed low-damage completions with good economic return. In lower permeability reservoirs, this approach has not often been successful.
Previous studies offer numerous success stories for stimulating cased/cemented horizontal completions in low-permeability reservoirs.1-8 To achieve proper stimulation with a technique such as fracture-acidizing or hydraulic fracturing with proppants, operators must incorporate an economical, effective method for controlling fluid or proppant placement. However, operators faced with limited producing potential need to reduce well costs, so they often consider openhole or simple liner completions a necessity. Unfortunately, few proven technologies exist for controlling fracture placement in noncemented wellbores. In some cases, high risk or very high cost is associated with these technologies, depending on reservoir conditions or the potential for production improvement.
In attempting to solve these problems, operators have used several approaches. Some have succeeded both mechanically and economically; some have only been mechanical successes, while others have fallen short on both considerations. To achieve significant long-term production improvement, conventional proppant-laden fracturing treatments, waterfracs (those using very little proppant), and fracture-acidizing of carbonate formations all need some type of control over fracture placement along the horizontal. This paper examines several approaches used in attempting to solve these problems and analyzes the reasons why each succeeded or failed mechanically and/or economically.
Effects of Reservoir and Operational Parameters on the Succession-of-Pseudosteady-States Modeling of a Closed Gas Reservoir
Authors: Lee K. S. 
Published: December 2007

Abstract
The succession-of-pseudosteady-states approach, originally established for linear diffusion problems, has been extended to calculate the long-time behavior of real gas flow in a closed reservoir. The applicability and limitations of the approach were examined through a series of numerical simulation works and error analysis. It is intent of this paper to provide a quantitative guideline on the use of pseudosteady-state approach to real gas flow problems.
To extend the pseudosteady-state approach, a linearized form of gas diffusivity equation was derived by introducing normalized pseudovariables to the equation. Extensive numerical simulation study has then been performed to quantify effects of various reservoir and operational parameters which may develop nonlinearities in the gas flow problems. The parameters considered are permeability, pressure, flowrate, and gas properties. Results of simulation studies have been examined with cumulative error analysis. For most cases, a fairly good agreement was observed between the predictions from the pseudosteady-states model and conventional reservoir simulation. Error analysis demonstrates that the permeability and reservoir pressure can affect the results of a succession-of-pseudosteady-states approach. The accuracy depends weakly on the flowrate, and is almost independent of specific gravity. Except for the cases of very low permeabilities, however, computations indicate that neglecting infinite-acting flow behavior does not introduce serious error in the procedure. The validity and computational efficiency of the succession-of pseudosteady-states approach for the analysis of gas reservoirs has been confirmed in the present work.
A Nested Neuro-Fractal-Stochastic Technique for Modeling Naturally Fractured Reservoirs
Authors: Tran Nam H. , Rahman M. K. , Rahman Sheik S. 
Published: December 2007

Abstract
Naturally fractured reservoirs (NFR) have recently attracted intensive research attention, because the world market is increasingly under pressure to exploit energy from unconventional sources such as naturally fractured oil, gas and hot dry rock reservoirs. Modeling of naturally fractured reservoirs has so far been considered complex and progress is still inadequate. This paper presents a new integrated methodology to model natural fracture networks. The methodology integrates the features of geological, statistical and artificial intelligence techniques in a nested loop to characterize fracture networks observed in the field, and then to simulate it.
Natural fracture parameters such as size, orientation and aperture are of different scales and relevancies. Their characterization is also, to some extent, technique dependent. Some secondary parameters such as fracture density and fractal dimension are therefore defined for better description of these reservoirs. The relationship between the primary and secondary fracture parameters is complex and has not yet been fully understood. A neural network tool has been incorporated in the proposed methodology to establish this relationship by processing field data available from logs and core analysis, and to define the relative importance of primary parameters in this relationship. Combining the primary and secondary parameters at well locations, natural fracture networks are simulated stochastically in the whole reservoirs. The nested technique is used to model different degrees of heterogeneity in the reservoir: at the reservoir scale, locations and properties of major faults and joints are taken into account; and at the well-bore scale, a fracture network is mapped with its characterized fracture parameters. The simulated reservoir is thus expected to map more closely with the physical distribution of fractures and their properties than that are achieved so far with simplified stochastic-fractal approaches.
In-Situ Contamination Monitoring and GOR Measurement of Formation Fluid Samples
Authors: Dong C. , Mullins O. C. , Hegeman P. S. , Teague R. , Kurkjian A. , Elshahawi H. 
Published: December 2007

Abstract
Formation fluid sampling early in the life of a well ensures that vital information is available for timely input to field planning decisions. Particularly in subsea wells, flow assurance is a major concern, and formation fluid samples from openhole logging help operators optimize investment in both upstream and downstream facilities.
Oils have different color due to the amount of large, complex aromatic compounds they contain. Since synthetic and oil-base drilling muds contain simple aliphatic compounds, they absorb little in the shorter wavelength color channels. The Oil-Base Contamination Monitoring (OCM) technique uses optical means to monitor the buildup of color during sampling. The technique provides real-time analysis of sample contamination, as well as prediction of how long it will take to achieve an acceptably low level of contamination.
As reservoir fluid replaces filtrate in the flow line, the optical density (OD) of the methane signal also increases, in proportion to the oil's methane content. Methane detection is essential for condensates and for lightly colored crude oils. For such fluids, the color buildup becomes difficult to detect; however, the high methane content of these fluids makes possible a reliable methane-based OCM algorithm. Furthermore, the methane content can be used to determine the gas/oil ratio (GOR) of the sample. When these methane-based techniques are applied for darker oils, the color absorption of the crude extends to the near infrared region and covers the methane molecular vibration peak, resulting in a higher methane signal optical magnitude. If uncorrected for, this would result in errors in the methane-based contamination prediction and GOR determination.
In this paper, we show how to measure GOR downhole during sampling using the OD of the methane signal. We also describe a decolorization algorithm to remove the color effect from the methane optical channel. The algorithm is based on the exponential decay of color absorption toward the high wavelengths in the near infrared region. After decolorization, the methane channel contains only methane molecular vibration absorption, which is then used to derive an accurate crude oil contamination value and GOR.