bluuebunny/crossref_metadata_2025_split huggingface dataset:
Flow Units: From Conventional to Tight Gas to Shale Gas Reservoirs
Authors: Aguilera Roberto 
Published: July 2010

Abstract
Process or delivery speed represented by the ratio of permeability and porosity is shown to provide a continuum between conventional, tight and shale gas reservoirs. The surprising result, based on core data from various North American basins, leads to distinctive flow units for each type of reservoir.
The approximate boundary between viscous and diffusion dominated flow is estimated with Knudsen number. Viscous flow is present, for example, when the architecture of the rock is dominated by megaports, macroports, mesoports and sometimes microports (port = pore throat). Diffusion flow on the other hand is observed at the nanoport level. Results from this research compare well with the observation that grains and pores are smaller in shales as compared with tight and conventional gas formations.
The process speed concept has been used successfully in conventional reservoirs for several decades. However, the concept presented in this paper for tight gas and shale gas reservoirs, with the support of core data, is new, and permits differentiating between viscous and diffusion dominated flow. This is valuable, for example, in those cases where the formation to be developed is composed of alternating stacked layers of tight sands and shales, or where there are lateral variations due to facies changes.
It is concluded that there is significant potential in the use of process speed as part of the flow unit characterization of unconventional gas reservoirs.
Selection of Three-Phase Relative Permeability Model for Mixed-Wet Reservoirs
Authors: Behzadi S. H. , Alvarado V. 
Published: July 2010

Abstract
The most widely used three-phase relative permeability models are Stonel and Baker. The mixed-wet condition is perhaps the most frequently encountered wetting condition worldwide. Two models for mixed-wet systems have been developed in recent times, Blunt's (2000), which is somewhat complex to use in simulators, and Jerauld's (1997) that is relatively easier to implement. The model incorporates the effect of interfacial tension (IFT) between phase pairs as well as the ability to model mixed wettability and incorporates IFT effects. In this paper Stonel and Jerauld's models are compared.
We illustrate the differences in performance prediction between the two models in three-phase oil relative permeability (kro) for the same two-phase relative permeability data sets. We show how these formulations can be used in commercial simula¬tors. Recovery prediction differences as well as the effect of gas miscibility on oil relative permeability to water (krow) are shown. Results show that three-phase kro values, based on Jerauld's model, can be up to 2 times lower than those predicted by using Stonel and consequently recovery might be overestimated by 21% at immiscible condition, while at 80% miscibility, the underestimation becomes only 0.75% if Stonel model is used. Gas miscibility diminishes krow, resulting in lower recov¬ery. The recovery is overestimated by 13% at 80% miscibility, if the effect of miscibility is only accounted for oil-gas relative permeability. We show the importance of using an adequate three-phase model in mixed-wet system in addition to account¬ing for the effect of gas miscibility on oil-water relative permeability.
Nonisothermal Assessment on the Performance of Polymer Flood in the Reservoir with Elevated Temperature
Authors: Lee Kun Sang 
Published: July 2010

Abstract
Accurate assessment of the potential of a nonisothermal polymer flood process for mobility control requires a model on the viscosities of reservoir fluids as a function of temperature. The temperature dependence of viscosity was included in the reservoir model and an extensive numerical simulation was conducted to examine the effects of temperature-related viscosity model on the reservoir performance during polymer flood in the reservoir with elevated temperature. A three-dimensional numerical model for fluid flow, mass transport, and energy balance is used to analyze the performance of the reservoir operating under polymer flood followed by waterflood. The nonisothermal scheme can be used as a quantitative tool to evaluate the comparative studies of different polymer flooding scenarios with respect to temperature dependence of fluids’ viscosities. Results of cumulative oil recovery and water-oil ratio (WOR) at the production well and injectivity at the injection well are presented for various types of temperature dependencies, reservoir temperature, and oil viscosities.
The simulation scheme with thermal dependence of fluids’ viscosities allows a more quantitative prediction of reservoir performance. Significant improvement in predicted oil recovery and reduction in WOR is obtained for the case of including temperature dependencies of both water and oil because the reduction of oil viscosity is larger than that of brine viscosity. The inclusion of heat loss to over/underburden formations had limited effect on the oil recovery because of relatively small temperature difference under the conditions considered in this study. More rapid reduction of oil viscosity results in the considerable reduction in mobility ratio and significant increase of oil recovery at higher temperature. High oil recovery was obtained with small values of oil viscosity, but the improvement is not proportional to the reduction of oil viscosity.
Internal Pipeline Corrosion Study on the Changes From Oil to Gas Production
Authors: Wang H. V. , Allan K. 
Published: July 2010

Abstract
The switch from oil to gas production will dramatically change the operation conditions in the producing wells, topside facilities, and transportation pipelines. Besides the changes in gas/liquid compositions, operating pressure and temperature, multiphase flow in the pipeline will also shift from a high-liquid load pattern to a low-liquid load pattern. Typically, the demarcation point between the two patterns could be considered as GOR of 1000 SCF/BBL. Forecast of the field studied in the paper indicates that the transition might happen after a few years and GOR will increase gradually with the aging of the wells. The changes will have a great impact on internal pipeline corrosion and corrosion inhibition and thus require a systematical study to identify the keys parameters and strategize a suitable corrosion management plan.
In this paper, the experiences gained from current corrosion monitoring and corrosion inhibition programs were reviewed first. Corrosion scenarios were also analyzed for future operational conditions by conducting both fluid- dynamic analysis and corrosion risk prediction along the pipeline for a wet gas environment. In order to study the impact of flow on the corrosion inhibitor application, laboratory tests were carried out to evaluate the incumbent corrosion inhibitor for future wet gas environment. The lab study focused on testing the partitioning capability of the corrosion inhibitor at different water cuts (10% – 100% water cut) and the localized corrosion risk due to the high shear stress using both rotating cylinder electrode (RCE) apparatus and rotating cage type of autoclave. The study showed that, though the corrosion risk of the system was determined to be relatively low, the option of applying corrosion inhibitor by batch treatment should be ruled out due to the possible breakdown of inhibitor film in a turbulent flow, which is associated with high shear stress and subject to gas bubble impingement. Lab tests also indicated that continuous treatment of 25 to 50 ppm corrosion inhibitor could minimize the localized corrosion risk of carbon steel pipeline in a 150-Pa shear stress flow.
Computer Modeling and Simulation of High Frequency Vibration Recovery Enhancement Technology in Low-Permeability Reservoirs
Authors: Guo X. , Du Z. , Li Z. 
Published: July 2010

AbstractComparing to conventional production methods, high frequency vibration recovery has many advantages during development of low permeability reservoirs, such as effectively improving reservoir permeability, deceasing fluid mobility, enhancing single well production, low cost and low pollution. However, at present, researches on high frequency vibration recovery are limited to qualitative interpretation, and quantitative research and theoretical system are lack of completeness, which cause the disability of correctly choosing the optimistic production method and the optimization of the technical parameters. In this paper, by analyzing and integrating principle and theories of reservoir engineering, flow in porous medium, acoustics, rock mechanics and numerical analysis, acoustic pressure relation equation was established and a quantitative description about the porous media reservoir and fluid parameters alteration after high frequency vibration effect were attained. Furthermore, a preliminary mathematical model and computer modeling under high frequency vibration effect in low permeability reservoir were developed. This study was successfully applied to simulation of high frequency vibration recovery in a low permeability reservoir in Western China. The result showed that high frequency vibration recovery could stimulate single well production and improve the development efficiency of low permeability reservoir.
Detecting Shallow Drilling Hazards in Large Boreholes Using LWD Acoustic Measurements
Authors: Prilliman J. , Tang X. , Archer M. 
Published: July 2010

Abstract
Shallow drilling hazards present a significant risk to the health, safety, and environment of upstream oil and gas operations. Shallow marine formations are often near the critical porosity limit, where the sediment is very poorly sorted, mechanically weak and often unconsolidated. As the sediment begins to compact, well-construction challenges are created as formation stresses and fluid pressure changes, usually resulting in the operator having to set extra casing strings near the surface. The United States Department of the Interior, Minerals Management Service (MMS) requires the use of a diverter and a conductor string of casing if there is any possibility of a shallow hazard in the area of a proposed well. Proving shallow hazards do not exist in the area requires resistivity and porosity logs approved by the MMS. This operator requested these logs be run in 22 and 17 ½ in. boreholes using Logging While Drilling (LWD) technology as no wireline logging was planned. In large hole sizes, the porosity log is generally the limiting factor for most wireline and LWD technologies, with nuclear measurements from most vendors designed for hole sizes no bigger than 12 ¼ in. LWD Acoustic measurements in this well provided acceptable determination of porosity in borehole sizes up to 22 inches in extremely slow formations.
The objective of this application was to acquire an LWD acoustic compressional slowness log below the drive pipe. Modeling shows and supports the ability to measure in this demanding environment where the compressional slowness often approaches that of the drilling mud. A 9 ½ in. LWD acoustic device was optimized for shallow data acquisition for the large borehole size and very slow acoustic velocities anticipated. While drilling, real-time LWD logs showed conclusive evidence of the absence of hazards and were immediately accepted by the MMS for the waiver.
This paper validates the feasibility of using LWD logs to gain a conductor waiver from the MMS. Benefits include reduced operating costs associated with a wireline program and the savings involved in removing the conductor string from the casing program. On this multi-well batch drilling project operational savings of about 2.15 million USD were realized.
Horizontal Well Placement Optimization for Heavy Oil Production in Girasol Field
Authors: Cuadros Jaime , Ossa Nicolas , Cuadros Guillermo , Rojas Esteban 
Published: July 2010

Abstract
Girasol, one of the largest heavy oil fields in Colombia, is located in the Middle Magdalena Valley basin. The field is composed of a shallow sequence of sediments of fluvial origin in which sandstone channels contain heavy oil of 11- to 13°-API gravities.
Similar fields in the country are developed using thermal recovery techniques via vertical or deviated wells. As horizontal wells have proved to offer advantages for enhanced oil recovery, from the first stages the Girasol field development plan included the execution of horizontal wells to apply cyclic steam injection techniques.
Four different stacked sandstone reservoirs, located at 1,100-ft to 1,600-ft true vertical depth (TVD) below surface, are the main targets. The project included a series of parallel horizontal wells of 1,200-ft to 2,350-ft lateral extension, with a fixed lateral spacing and vertically placed to drain one reservoir per well. The targets were geological, 10- to 20-ft thickness to maximize production.
Horizontal well placement in this scenario—shallow, thin, and friable formations— is, in general, difficult to achieve with the use of conventional geosteering techniques, as they generally fail to identify unexpected changes in the reservoir geometry, increasing the risk of poor results. This risk was minimized by using deep, directional electromagnetic measurements while drilling, enabling the reservoir geometry mapping in real time, several feet from the borehole.
Results of the use of this technology—combined with continuous inclination measurement near the bit and an advanced geosteering process— include 96% average net pay, minimization of unproductive drilling, rig time savings, and sidetracks avoidance after 24 horizontal wells drilled to date. The strategy used for horizontally placing wells in the Girasol field can be used in similar fields worldwide.
Sand Settling and Locations of High Erosion in Subsea Production System
Authors: Shirazi S. A. , McLaury B. S. , Sow E. , Butter M. , Folefac A. , Hassaballa S. A. 
Published: July 2010

Abstract
When higher than expected sand volumes were produced from Gas Field #1 after a 2nd well group was brought on line it was initially believed that the sand production came from these new wells. Several sand production and erosion studies were initiated to investigate this sand production. Sand transport studies were conducted as part of the investigation. These studies demonstrated that the sand was produced by the 1st well group, rather than the 2nd, but that the sand was not being transported through the main export lines until after the 2nd well group came online and the gas velocities through the flowlines increased. These findings were supported by other observations made in the field following the initial detection of the sand production, while the studies were on going.
Erosion calculations, covering the full range of flow conditions that are expected over the life of the field, were conducted to examine and determine locations of high particle impact rate. The results of these calculations are used to optimize present and future ultrasonic thickness (UT) measurement programs so that critical locations can be targeted with higher localized resolution. Experimental flow studies were also performed to validate the Computational Fluid Dynamics (CFD) erosion calculation model. This CFD model was in turn used to model those parts of the subsea infrastructure that are most prone to erosion under field operating conditions, the Pipeline End Manifold (PLEM). For these flow studies a scaled down version of the PLEM, was built. The CFD results agreed well with the experimental results indicating that the CFD results are accurate in predicting the location of impacts. This was a very important finding because the CFD modeling is used to examine actual pipe geometries within the well and subsea flowline system for various flow and operating conditions during the life of the wells. The results from this work led to more focused and accurate erosion monitoring.
Simultaneous Production of Oil and Gas Reserves From Single Wellbore
Authors: Nagib Mohamed , Ezuka Ifeanyi , Nasr Ghasem G. 
Published: July 2010

Abstract
Maximising oil recovery in thin and ultra-thin (&lt;30ft) oil columns is a challenge as a result of conning or cresting of unwanted fluids into the wellbore in both vertical and horizontal wells. There is considerable oil left behind, above the well completion in the reservoir. This may also occur in horizontal well when bottom or edge water encroachment or invasion takes place.
The development of the gas resources from these reservoirs is a major challenge as regulators want optimal development plan for the oil rim before project approval is made. This can delay upstream gas supply to LNG projects and grind down project value. A smart development strategy has been proposed for the development of these challenging reservoirs. This involves the use of intelligent multilateral well in simultaneous oil and gas development; the first (top) horizontal lateral well legs of the multilateral well will be completed at the crest of the reservoir in the gas cap. The second or lower horizontal lateral well leg will be completed, right above the gas-oil contact.
Extensive numerical reservoir flow simulation has been used to demonstrate the ability and possibility of using a single wellbore for simultaneous oil and gas production. This proposed development strategy will provide high impact on the asset of such oil and gas reservoir by providing a cost effective technology solution. The numerical simulation results show that the intelligent multilateral well will significantly improve the overall cumulative production of gas and oil from a thin oil reservoir with large gas cap as compared to conventional wells and also provide opportunity for auto gas lift for low API gravity crude.
This paper presents; i) the use of intelligent multilateral wells to simultaneously produce oil and gas from the same wellbore in the thin oil reservoir and ii) provide information on the delay and reduction of excess production of unwanted fluids (water) during oil and gas production from thin oil reservoir using intelligent well technology including cost effectiveness.
Miscible Gas Injection: A Successful Experience Leading to Proper Reservoir Management Through Simulation Study A Carbonate Case Study
Authors: Sajjadian S. , Sajjadian V.A. A , Roostaeian M. , Ghafoori M. R , Ataabadi V. Mahmoudian 
Published: July 2010

Abstract
Miscible gas displacement is known as one of the most efficient EOR methods throughout the world. The mechanism is seem to be promising in homogeneous sandstones but is quite challenging when it comes to heterogeneous carbonates.
The studied field is among the tight heterogeneous carbonates from southwest of Iran. The reservoir in an undersaturated high pressure oil reservoir with no active aquifer. Due to low permeability of the reservoir, a miscible gas injection was thought to be efficient in increasing the oil recovery, maintaining the reservoir pressure and increasing the production plateau. A full compositional simulation model was built taking into account reservoir heterogeneities. The simulation study includes history matching of the past reservoir performance, optimization of the gas injection well number and location, and optimization of gas injection and oil production rates. After running sensitivity analysis, the reservoir engineers came up with drilling of the 6 crestal gas injection wells.
In Addition, the water injection was thought as an alternative for EOR purpose but it didn't show up well and was given up.
The outcome of this simulation study nominates the miscible gas injection as the most promising method concerning the reservoir management purposes as it increases the recovery from 16% to around 42% through 40 years of production and could maintain the plateau of 120000 bopd up to 19 years from the production start.
Integrated Uncertainty Quantification by Probabilistic Forecasting Approach in the Field Development Project
Authors: Sajjadian S. , Asheghi A. , Roostaeian M. , Ghafoori M. R , Sajjadian V. A , Hashemi A. 
Published: July 2010

Abstract
Development studies examine the importance of geologic, engineering, and economic parameters to formulate and optimize production plans. If there are many factors, these studies are high-priced unless simulation runs are chosen and analyzed efficiently. Reservoir studies require integration of geological properties of the reservoir, drilling and production strategies, and economic parameters. Integration is complex, because parameters such as permeability, drive mechanism, structural framework, and fluid saturation distributions are uncertain. Uncertainty in permeability, for example, could be caused by prediction at unknown locations from inexact seismic data, poorly distributed of precise well data and imprecise seismic data. Therefore the impact of uncertainty levels in key geologic and production parameters such as NTG, permeability, porosity, vertical transmissibility, skin factor must be assessed.
The application of the system on a single, sector carbonate reservoir unit is taken through a development-plannig case study based on Field Development Plan, FDP. Ultimate recoveries, profiles, and economics for the range of possibilities are evaluated.
Uncertainty quantification is attained in the development of a method that can model and quantify uncertainty in reservoir simulation in an efficient and practical way. In this study variety of approaches are investigated to estimate the uncertainty in a recovery prediction. The methodology which is employed in this study uses Monte Carlo simulation approach (probabilistic forecasting) and efficient selective simulation runs with simultaneous, multi variable input modifications. The results indicate that in terms of reserves points of view the main uncertainties are represented by NTG and permeability distribution. This can be attributed to indigenous heterogeneous carbonate reservoir deposition and dissolution. The uncertainity to the OOIP is also affected mainly by the reservoir structural framework; reservoir top depth variations.
Thermodynamic Fluid Characterization in a Compositional Reservoir Model: A Field Gas Injection Study
Authors: Sajjadian S. , Ghafoori M. R. , Roostaeian M. , Hashemi A. , Asheghi A. , Sajjadian V. A. 
Published: July 2010

Abstract
In order to create an integrated simulation model, it is essential to have a fluid characterization based on revision and validation of the available laboratory data. These include PVT studies, production data, RFT logs, etc. In case of EOR process modeling, it is necessary to also consider the special fluid tests (swelling test and displacement measures on cores) which permit the evaluation of the injected gas effect on the original fluid properties in the reservoir, particularly at the saturation pressure.
The thermodynamic study based on the available experimental PVT data, taken from three appraisal wells of a carbonate oil field is presented. The fluid system flowing throughout two reservoir levels is characterized by means of equations of state finalised to a full 3D gas injection reservoir study. The objective is optimizing the field production strategies considering the injection of natural gas.
Overview of all the experimental data shows a good agreement among the tests performed on samples belonging to the same level. In this study two equations of state (three parameters Peng-Robinson equation) have been calibrated for the two levels. The simulated PVT parameters by the tuned EOS for the two levels are in good agreement with the already measured experimental data. In addition, the swelling test simulation shows a fair match within limits of cubic EOS.
The slim tube experiments performed by laboratory to state the miscibility/immiscibility condition of the reservoir oil with respect to the gas extracted at the separators are also simulated. Consequently the sensitivity of the miscibility conditions to possible variations of the composition of the injected gas is investigated.