Abstract In order to delay the water breakthrough and reduce water production once breakthrough occurs in the bottom water reservoirs, the water control mechanism of novel C-AICD is studied. The paper describes the laboratory testing of C-AICD, AICD and ICD performed to evaluate the performance of C-AICD and the differences between C-AICD, AICD and ICD. Results from single phase experimental flow testing are presented and discussed. The testing was conducted in a dedicated flow facility with water, oil and mixed phase fluild. It is under the same experimental conditions to test the water control effect of ICD, AICD, and C-AICD and be analyzed based on the recorded pressure and flow rate data. The testing results showed that C-AICD could take advantage of AICD and ICD. It could function as a passive ICD to achieve uniform inflow at the beginning of production, and then function as AICD to autonomously restrict water production in the middle and late stages. Based on a water control design and simulation of one horizontal well, it is found that the comprehensive water-cut of C-AICD well in the production life is about 13% lower than that of the common screen well, which provides a new technical method for economic and effective water-control in oil fields.

Abstract This paper develops a novel WFS model for transient pressure analysis in multi-stage fractured horizontal wells. In the WFS model, two concepts called WFS pressure and WFS index are introduced and an additional skin factor in the interface of inner and outer regions is applied based on a radial composite reservoir. Then, a novel multi-stage fractured horizontal well model is developed by considering the WFS, stress-sensitivity effects, and finite-conductivity fractures. The reservoir model is solved by the perturbation transformation, Laplace transform, and numerical inversion. While the fracture model is solved by fracture discretization and superposition principle. Finally, the bottom hole pressure is obtained. Following that, model verification and sensitivity study are performed. It is found that the flow regimes of the WFS model includes bilinear flow, linear flow, first radial flow, bi-radial flow, pseudo radial flow, and WFS flow. An interesting feature of "hump" caused by WFS flow exhibits in the pressure derivative curve. The results of sensitivity study show that the height of that "hump" increases as the WFS pressure increases, but is independent of WFS index. What’s more, WFS flow exhibits a closed boundary flow when the WFS index is equal to zero, while it appears as a constant pressure boundary flow when WFS pressure is very tiny. Through the WFS model, the fluid supply characteristics of tight gas reservoirs are fully understood.

Abstract CO 2 injection into saline aquifer has gained attention as an effective technique to permanently secure the produced anthropogenic gas from high CO 2 gas field in South East Asia region. However, problem such as injectivity impairment has been faced by operators and researcher has attributed the interactions between CO 2 -brine-rock to be the major cause. This research investigated the effect of CO 2 displacement schemes, reservoir rock permeability, formation brine type and concentration on CO 2 injectivity. CO 2 coreflood experiment with detailed characterization of the rock and effluent produced are presented. Various core samples which represent low and high permeability of typical geological storage for sequestration were selected. The core samples were analyzed using X-Ray Fluorescence (XRF), X-Ray Powder Diffraction (XRD) and Field Emission Scanning Electron Microscopy equipped with Energy Dispersive Spectroscopy (FESEM-EDX). Then it was saturated with synthetic formation brine composed of 6,000 ppm, 30,000 ppm or 50,000 of either Sodium Chloride (NaCl), Potassium (KCl) or Calcium Chloride (CaCl 2 ). Lastly, core samples were injected by either supercritical CO 2 (scCO 2 ), CO 2 -saturated brine and combination of CO 2 -saturated brine and scCO 2 and the pressure drop profile was recorded. Fines were then being separated from the collected effluent for further analysis. FESEM images of the pre- and post-injection core samples were compared to assess physical changes. Results indicated that CO 2 injection scheme, flow rate, brine concentration and initial rock permeability are the principal factors that contribute to the porosity and permeability alteration of the core samples. Moreover, FESEM-EDX analysis of the produced fines shows precipitated salt, silica grain and kaolinite were migrated during scCO2 injection. It is suggesting that minerals were dissolved and precipitated, resulting in detachment of silica particles and formation of new secondary minerals, some of which plugged the pore spaces reducing the permeability. In addition, core saturated with CaCl 2 brines are the only samples that showed permeability improvement after CO 2 flooding experiment.

Abstract The study of pressure transient behavior in fractured-vuggy reservoirs has recently received considerable attention because a number of such reservoirs have been found worldwide with significant oil and gas production and reserves. In recent years, the use of highly deviated wells (HDW) is considered an effective means for developing this type of gas reservoir. However, in many fractured-vuggy reservoirs unexpected high gas production have been observed which cannot be identified with pressure transient models of horizontal well with pseudo state triple-porosity interporosity flow. This paper presents a semi-analytical model that analyzed the pressure transient behavior of HDW in triple-porosity continuum medium which consist of fractures, vugs and matrix. Introducing pseudo-pressure, Laplace transformation and Fourier transformation were employed to establish a point source and line source pseudo-pressure solutions in Laplace space. Then the pseudo-pressure transient curve was got by numerical inversion. Furthermore, the flow characteristics were analyzed thoroughly by examining the curve which is mainly affected by inclination angle of HDW and interporosity flow coefficients between different pore media. Sensitivity analysis on the pressure transient behavior was performed by varying some important parameters such as the inclination angle, fracture storativity ratio and interporosity flow coefficients. Finally, a field case was successfully used to show the application of the presented semi-analytical model. With its high efficiency, this approach will serve as a reliable tool to evaluate the pressure behavior of HDW in fractured-vuggy carbonate gas reservoirs.

Abstract Dynamic reserves calculation is an important basis in the process of abnormally high-pressured offshore gas fields development. Based on the early stage development experience in abnormally high-pressured gas fields, the calculated dynamic reserves will be larger than the actual value. And the number of development wells in offshore gas fields is relatively small, which makes it more difficult to accurately calculate dynamic reserves. If the gas fields development dynamic was not acquired in time, the gas fields development adjustment would not be made effectively. Therefore, how to calculate the dynamic reserves accurately in the early stage is the key for this type gas fields development. In this paper, a new method of calculating the dynamic reserves for abnormally high-pressured offshore gas fields early stage development has been put forward. First of all, the complete dynamic reserves prediction model was established with the use of material balance method. Secondly, in the process of model solving, the calculation model of effective compressibility coefficient was modified for the first time without laboratory experiment. Moreover, in order to improve the calculating precision of the early stage development dynamic reserves, the quality control model was established and the R factor was introduced. The accuracy of dynamic reserves calculation is determined by the production data, pressure data, R value, etc. The greater R value is, the higher the accuracy is. When the R factor is between 0.9 and 1.0, the result of dynamic reserves calculation is right. Otherwise, we need to recalculate the input data. This new method has been applied in the early stage development of X abnormally high-pressured offshore gas field, and the calculated dynamic reserve is 186.66Bcf. If using traditional method, the dynamic reserve is 293.20Bcf, which is 36% larger than the new calculated dynamic reserve. The reservoir dynamic test data and geological static data have shown that the result of using this new method is more reasonable. This paper provides a quantitative and operational new method to accurately calculate the dynamic reserves in abnormally high-pressured gas fields, and can guide the early stage development adjustment effectively.

Abstract Mesozoic age Golapalli sands are found in the Krishna Godavari Basin, located in the East coast of India. These sands are highly prospective for hydrocarbon exploration and development. They comprise of syn rift sediments, often, exhibiting low permeability. In general, these reservoirs do not flow naturally without hydraulic fracturing. Oil presence in Golapalli sands has already been proven in the basin from the exploratory wells. However, conventional saturation modeling using basic petrophysical logs has proved futile in establishing a definite oil water contact (OWC). This adds further complexity in the reserve evaluation and the hydraulic fracturing design. Moreover, the field is divided into multiple fault blocks with localized OWCs. During the initial appraisal phase, wells that were hydraulically fractured produced oil with high water cut. This prompted re-evaluation of saturation modelling with 3 further appraisal wells. All new wells were selected at different fault blocks within the field and were to be drilled as slim holes of 5-7/8in diameter in reservoir section. Potential intervals with natural fractures were successfully evaluated using advanced sonic data. Zones of interest were selected integrating the fractures network identified with advance sonic measurements and high porosity values obtained from basic neutron-density logs. To constrain inversion resistivity-based saturation modelling, a new workflow was adopted to determine reservoir fluid movements prior to hydraulic fracturing in less than 0.05mD formation. Through this approach, fluid saturations were successfully evaluated using a deterministic downhole fluid identification which helped in reducing saturation uncertainties while demarking the transition zone between oil and water in 0.05mD formation. With known oil zone identified, advanced sonic measurements were used to design effective hydraulic fracture models. A successful hydraulic fracture was initiated with excellent oil production with significantly reduced water cut compared to previous wells. In this paper, a novel workflow will be presented that will help in characterizing fluids in tight sands (permeability less than 0.05mD). This workflow integrates the basic openhole logs and formation testing with conventional resistivity-based saturation modeling to accurately pinpoint the OWC in the tight sands. This workflow has applicability in unconventionally tight reservoirs where there is uncertainty in fluid saturations or fluid contacts. Through this methodology, the propagation of hydraulic fracture into the water zone can be prevented which will greatly help in reducing the water cut in such conditions.

Abstract There is large amount of heavy oil resources whose oil viscosity over 350 mPa·s in Bohai Oilfield and their producing degree and production performance are relative low for lacking of effective exploitation technology. For seeking effective production technology for heavy oil exploitation, the steam and flue gas co-injection technology is proposed and studied. Considering the limited platform space, miniaturized steam and flue gas generator is designed and applied for field test. Besides, integrated matching technologies such as sea water desalinization, heat insulation, anticorrosion are also studied and developed. The south part of NN Oilfield was selected to be the target oilfield and the first thermal pilot area in Bohai Oilfield in 2008. Until now, the pilot in NN Oilfield has lasted for 10 years, nearly 30 well times of stimulation has been conducted and part of these wells has entered the third stimulation cycle. Compared with natural energy production, peak oil production and periodic oil production of thermal production are both greatly improved. With the increase of the stimulation cycle, the gas channeling problem has bad influence on the production performance, and the production rate declines rapidly. Steam flooding might be an effective replaced technology after huff and puff for further enhancing oil recovery of offshore heavy oilfields.

This paper develops a novel WFS model for transient pressure analysis in multi-stage fractured horizontal wells. In the WFS model, two concepts called WFS pressure and WFS index are introduced and an additional skin factor in the interface of inner and outer regions is applied based on a radial composite reservoir. Then, a novel multi-stage fractured horizontal well model is developed by considering the WFS, stress-sensitivity effects, and finite-conductivity fractures. The reservoir model is solved by the perturbation transformation, Laplace transform, and numerical inversion. While the fracture model is solved by fracture discretization and superposition principle. Finally, the bottom hole pressure is obtained. Following that, model verification and sensitivity study are performed. It is found that the flow regimes of the WFS model includes bilinear flow, linear flow, first radial flow, bi-radial flow, pseudo radial flow, and WFS flow. An interesting feature of "hump" caused by WFS flow exhibits in the pressure derivative curve. The results of sensitivity study show that the height of that "hump" increases as the WFS pressure increases, but is independent of WFS index. What’s more, WFS flow exhibits a closed boundary flow when the WFS index is equal to zero, while it appears as a constant pressure boundary flow when WFS pressure is very tiny. Through the WFS model, the fluid supply characteristics of tight gas reservoirs are fully understood.

Dynamic reserves calculation is an important basis in the process of abnormally high-pressured offshore gas fields development. Based on the early stage development experience in abnormally high-pressured gas fields, the calculated dynamic reserves will be larger than the actual value. And the number of development wells in offshore gas fields is relatively small, which makes it more difficult to accurately calculate dynamic reserves. If the gas fields development dynamic was not acquired in time, the gas fields development adjustment would not be made effectively. Therefore, how to calculate the dynamic reserves accurately in the early stage is the key for this type gas fields development. In this paper, a new method of calculating the dynamic reserves for abnormally high-pressured offshore gas fields early stage development has been put forward. First of all, the complete dynamic reserves prediction model was established with the use of material balance method. Secondly, in the process of model solving, the calculation model of effective compressibility coefficient was modified for the first time without laboratory experiment. Moreover, in order to improve the calculating precision of the early stage development dynamic reserves, the quality control model was established and the R factor was introduced. The accuracy of dynamic reserves calculation is determined by the production data, pressure data, R value, etc. The greater R value is, the higher the accuracy is. When the R factor is between 0.9 and 1.0, the result of dynamic reserves calculation is right. Otherwise, we need to recalculate the input data. This new method has been applied in the early stage development of X abnormally high-pressured offshore gas field, and the calculated dynamic reserve is 186.66Bcf. If using traditional method, the dynamic reserve is 293.20Bcf, which is 36% larger than the new calculated dynamic reserve. The reservoir dynamic test data and geological static data have shown that the result of using this new method is more reasonable. This paper provides a quantitative and operational new method to accurately calculate the dynamic reserves in abnormally high-pressured gas fields, and can guide the early stage development adjustment effectively.

CO 2 injection into saline aquifer has gained attention as an effective technique to permanently secure the produced anthropogenic gas from high CO 2 gas field in South East Asia region. However, problem such as injectivity impairment has been faced by operators and researcher has attributed the interactions between CO 2 -brine-rock to be the major cause. This research investigated the effect of CO 2 displacement schemes, reservoir rock permeability, formation brine type and concentration on CO 2 injectivity. CO 2 coreflood experiment with detailed characterization of the rock and effluent produced are presented. Various core samples which represent low and high permeability of typical geological storage for sequestration were selected. The core samples were analyzed using X-Ray Fluorescence (XRF), X-Ray Powder Diffraction (XRD) and Field Emission Scanning Electron Microscopy equipped with Energy Dispersive Spectroscopy (FESEM-EDX). Then it was saturated with synthetic formation brine composed of 6,000 ppm, 30,000 ppm or 50,000 of either Sodium Chloride (NaCl), Potassium (KCl) or Calcium Chloride (CaCl 2 ). Lastly, core samples were injected by either supercritical CO 2 (scCO 2 ), CO 2 -saturated brine and combination of CO 2 -saturated brine and scCO 2 and the pressure drop profile was recorded. Fines were then being separated from the collected effluent for further analysis. FESEM images of the pre- and post-injection core samples were compared to assess physical changes. Results indicated that CO 2 injection scheme, flow rate, brine concentration and initial rock permeability are the principal factors that contribute to the porosity and permeability alteration of the core samples. Moreover, FESEM-EDX analysis of the produced fines shows precipitated salt, silica grain and kaolinite were migrated during scCO2 injection. It is suggesting that minerals were dissolved and precipitated, resulting in detachment of silica particles and formation of new secondary minerals, some of which plugged the pore spaces reducing the permeability. In addition, core saturated with CaCl 2 brines are the only samples that showed permeability improvement after CO 2 flooding experiment.

Mesozoic age Golapalli sands are found in the Krishna Godavari Basin, located in the East coast of India. These sands are highly prospective for hydrocarbon exploration and development. They comprise of syn rift sediments, often, exhibiting low permeability. In general, these reservoirs do not flow naturally without hydraulic fracturing. Oil presence in Golapalli sands has already been proven in the basin from the exploratory wells. However, conventional saturation modeling using basic petrophysical logs has proved futile in establishing a definite oil water contact (OWC). This adds further complexity in the reserve evaluation and the hydraulic fracturing design. Moreover, the field is divided into multiple fault blocks with localized OWCs. During the initial appraisal phase, wells that were hydraulically fractured produced oil with high water cut. This prompted re-evaluation of saturation modelling with 3 further appraisal wells. All new wells were selected at different fault blocks within the field and were to be drilled as slim holes of 5-7/8in diameter in reservoir section. Potential intervals with natural fractures were successfully evaluated using advanced sonic data. Zones of interest were selected integrating the fractures network identified with advance sonic measurements and high porosity values obtained from basic neutron-density logs. To constrain inversion resistivity-based saturation modelling, a new workflow was adopted to determine reservoir fluid movements prior to hydraulic fracturing in less than 0.05mD formation. Through this approach, fluid saturations were successfully evaluated using a deterministic downhole fluid identification which helped in reducing saturation uncertainties while demarking the transition zone between oil and water in 0.05mD formation. With known oil zone identified, advanced sonic measurements were used to design effective hydraulic fracture models. A successful hydraulic fracture was initiated with excellent oil production with significantly reduced water cut compared to previous wells. In this paper, a novel workflow will be presented that will help in characterizing fluids in tight sands (permeability less than 0.05mD). This workflow integrates the basic openhole logs and formation testing with conventional resistivity-based saturation modeling to accurately pinpoint the OWC in the tight sands. This workflow has applicability in unconventionally tight reservoirs where there is uncertainty in fluid saturations or fluid contacts. Through this methodology, the propagation of hydraulic fracture into the water zone can be prevented which will greatly help in reducing the water cut in such conditions.

There is large amount of heavy oil resources whose oil viscosity over 350 mPa·s in Bohai Oilfield and their producing degree and production performance are relative low for lacking of effective exploitation technology. For seeking effective production technology for heavy oil exploitation, the steam and flue gas co-injection technology is proposed and studied. Considering the limited platform space, miniaturized steam and flue gas generator is designed and applied for field test. Besides, integrated matching technologies such as sea water desalinization, heat insulation, anticorrosion are also studied and developed. The south part of NN Oilfield was selected to be the target oilfield and the first thermal pilot area in Bohai Oilfield in 2008. Until now, the pilot in NN Oilfield has lasted for 10 years, nearly 30 well times of stimulation has been conducted and part of these wells has entered the third stimulation cycle. Compared with natural energy production, peak oil production and periodic oil production of thermal production are both greatly improved. With the increase of the stimulation cycle, the gas channeling problem has bad influence on the production performance, and the production rate declines rapidly. Steam flooding might be an effective replaced technology after huff and puff for further enhancing oil recovery of offshore heavy oilfields.

The gravity drainage process is one of the essential recovery mechanisms in the naturally fractured reservoirs. The contribution of the process to the ultimate oil recovery is quite uncertain, and it highly depends on the mathematical models that used in representing the process besides matrix characteristics such as shape factor and matrix block dimensions in addition to the matrix permeability. The fluid exchange rate between the matrix and fractures is the main controlling factor on the oil recovery, as most of the oil reserve stored in the matrix. Therefore, appropriate gravity model selection supported by accurate matrix characterizations can enhance the simulation accuracy and to avoid an overestimation to the oil recovery. In this work, an outcrop-based model was used to provide a realistic representation of the fracture network in a dual-porosity model. The constructed fracture model was employed to assess the impact of the gravity drainage mechanism. The investigation comprises several sensitivity scenarios and cases to evaluate the influence of both mathematical models and matrix properties using an intermediate resolution model with a single producer located the grid centre and a natural depletion scenario. The simulation results indicated remarkable differences in the producer's performance and productivity. The variation in performance is purely mathematical and related only to the gravity drainage options. Furthermore, the sensitivity results highlighted the significant impact of the matrix characteristics on the fluid exchange between the matrix and fractures, hence oil recovery. Therefore, misunderstand the impact of the mathematical models, and the influence of the matrix properties could result in a compound error in predicting the reservoir performance and its recovery, hence making an inappropriate development decision.

The use of foams is a promising technique to overcome gas mobility challenges in petroleum reservoirs. Foam reduces the gas mobility by increasing the gas apparent viscosity and reducing its relative permeability. A major challenge facing foam application in reservoirs is its long-term stability. Foam effectiveness and stability depends on a number of factors and will typically diminish over time due to degradation as well as the foam-rock-oil interactions. In this study, the effect of crude oil on CO 2 -foam stability and mobility will be addressed. Two-phase flow emulsification test (oil-surfactant solutions) and dynamic foam tests (in the absence and presence of crude oil) were conducted to perform a comparative assessment for different surfactant solutions. A microfluidics device was used to evaluate the foam strength in the presence and absence of crude oil. The assessment was conducted using five surfactant formulations, and using different oil fractions. The role of foam quality (volume of gas/total volume) on foam stability was also addressed in this study. The mobility reduction factor (MRF) for CO 2 -foam was measured in the absence and presence of crude oil using high salinity water and at elevated temperatures. The results indicated that foam stability has an inverse relationship with the amount of crude oil. Crude oil has a detrimental effect on foams, and foam stability decreased as the amount of crude oil was increased. There is good agreement between the results obtained from the two-phase emulsification test with those obtained from the dynamic foam tests in presence of crude oil. Depending on the surfactant type, the existence of crude oil in porous media, even at very low concentrations 5%, can significaly impact the foam stability and strength. The oil can act as an antifoaming agent; it enters into the thin aqueous films and destabilizes the film. This, ultimately, resulting in lower foam viscosity and less stable foams. Thus, the CO 2 MRF dropped significantly with higher oil fractions.

It is today an undoubted fact that the role of gas condensate systems has increased multifold in the global energy chain. However, the development and production of gas condensate systems remains a challenge to the petroleum industry due to its technical complexity. The production data analysis methodologies that has been followed throughout the industry to estimate gas condensate reservoir performance are conventional technologies which have proved ineffective in forecasting and estimating the gas condensate reservoir performance. The complexities involved in the gas condensate system like liquid dropout, condensate blockage and successive multiphase flow of gas and condensate along with the extensive early-transient infinite acting behavior are the root cause for the failure of the gas condensate system.The similarity method transforms the governing PDE for fluid flow into ODE written in terms of single independent variable that combines time and space. The similarity method provides a unique advantage of solving the obtained ODE without the need for linearization. In this paper, the Boltzmann transformation technique is applied to governing equations for multiphase flow for two inner boundary conditions (constant gas flow rate and constant bottomhole pressure) in linear and radial flow regimes. The proposed model is validated by using the line-source solution for single phase gas flow above the dewpoint. The proposed analytical solution for flow above the dewpoint pressure reasonably coincided with the line-source solution for flow above the dewpoint, thus, the proposed methodology can be used as an alternative and less time-consuming approach to predict reservoir performance in early transient multiphase linear and radial flow gas condensate systems. The capillary pressure effects considered in the paper were reasonably negligible considering the fact that a negligible capillary difference was used in fluid PVT properties. But was significant when incorporated as an additional pressure gradient term. This however, demonstrated that capillary pressure effects play a vital role in the production data analysis in gas condensate reservoirs. There is no analytical production analysis method developed to date has considered pressure-saturation as a function of a non-dependent dimensionless coordinate in multiphase (oil, gas and water) linear and radial flow systems. This paper aims to fill this knowledge gap by extending a modification of the similarity method to fully incorporate capillary pressure effect in multiphase linear and radial flow systems in which pressure and saturation are simultaneously considered as functions of a dimensionless coordinate.

This paper presents a comprehensive laboratory evaluation of Schizophyllan as an EOR polymer candidate for a selected peninsular Malaysia field. The polymer was chosen due to its well-known structure and properties. Schizophyllan, which originally produced from Schizophyllum commune was evaluated for its performance under controlled laboratory condition and the results are discussed accordingly. Rheology analysis at 96°C, showed that, at low concentration of 250ppm, Schizophyllan can achieve 11 cP which is about 90% more than live crude oil viscosity. Thermal Stability of this polymer was also excellent for the entire 3 months of exposure at reservoir temperature, whereby only 2.8% of viscosity degradation recorded with a very clear solution observed representing the heat and hardness resistance of the polymer. Injectivity test using actual native core indicated that, there was no plugging tendency or injectivity problem observed from the coreflooding test based on its low RRF value of 1.5. The resistance factor value of 9.93 indicates that this polymer is effective in viscosifying the water and injectable into the core. Dynamic adsorption study also showed that only 0.09mg/L of polymer was found adsorbed to the actual native core, despite the presence of clay in the core. Hence, from all the analysis, it was found that Schizophyllan meets the technical requirement to be applied as an EOR polymer

As a good deep profile control and displacement agent, polymer microspheres have broad application prospects in oil fields. Three kinds of microspheres (MG-1 to MG-3) with different particle sizes are synthesized and evaluated. The microspheres observed by SEM are regular spheres with initial particle sizes of 3μm, 6μm, and 10μm, respectively, and the swelling ratios are between 2 and 4. The matching relationship between microspheres and pore throat is established and the optimum matching factor is determined based on the long core migration experiment. The optimal matching factors of the microspheres obtained by the plugging strength are respectively 1-1.2 to MG-1 and 0.5-0.8 to MG-2. In the range of the best matching factors, the effect of injection parameters on microsphere plugging effect and profile improvement capacity is obtained by a long core migration experiment. The results show that the concentration of microspheres mainly affects the timing of their injected into the cores. The increase in concentration and injection speed will decrease the injection performance of microspheres. The concentration and injection velocity of microspheres do not affect the deep migration of microspheres in the core. Microspheres have better profile improvement and EOR effect, and the permeability ratio has less influence on them. Finally, the mechanism of microspheres with different particle sizes on profile control and displacement is studied by the microfluidic model. The results revealed that the plugging mechanism of microspheres are single microsphere direct plugging and bridging plugging with different particle size.

Relative permeability data are essential for almost all calculations of fluid flow in porous media. In addition, water and oil relative permeability curves play important roles in characterizing the simultaneous two-phase flow in porous media and predicting the performance of displacement processes. In this work, a pore-scale study of two-phase relative permeability in mixed-wet heterogeneous porous media at different capillary pressure and flow rate is presented. Multicomponent Johnson, Bossler and Naumann (JBN) method was employed to determine relative permeability using recovery, saturation and pressure results obtained from 3D Eclipse simulation model of a core sample. Mixed-wet states were created by altering the wettability of solid surfaces in contact with the non-wetting phase at the end of the unsteady-state simulation of initially water-wet porous media. JBN relative permeability results were compared to input relative permeability. The JBN results were found to match input data relative permeability especially at lower capillary pressure. The relative permeability of water in the mixed-wet porous media was found to decrease at lower to medium flow rates as water is pinned in smaller pore spaces leading to lower saturation and connectivity in wetting layers. Meanwhile, oil relative permeability increased due to higher connectivity and therefrom greater mobility. On the hand, oil relative permeability of in the mixed-wet porous media decreased at higher flow rates where water connectivity increased the relative permeability of water with increasing water saturation. A new JBN based model was developed to determine relative permeability and good matches were observed between the JBN calculated results and the input relative permeability. Therefore, the model can be utilized for various porous media applications at different wetting conditions.

In the shale oil reservoirs, the horizontal wells with large-scale fracturing treatments have been the most effective tools to enhance oil productivity. After large-scale fracturing treatments, many micro-seismic data showed that the fracture networks are generated in the reservoir along the wellbore. Understanding the complex fracture properties is the primary step for fracturing evaluation and productivity estimation. Thus, an efficient approach is needed to estimate the fracture properties. To improve this situation, a well-testing approach was proposed in this work to identify the fracture properties. This work was organized as follows: (1) developing a well-testing model of multiple fracture horizontal well (MFHW) including reservoir flow equations, fracture flow equations, and mass balance equations, (2) solving and verifying the proposed model using boundary element method, superposition principle, and numerical approach, (3) applying the well-testing model to investigate the pressure transient behaviors, and (4) estimating the fracture properties of shale oil wells from the Junggar Basin.

Exploration activity is always associated with many challenges such as uncertain pore pressure, and uncertain formation depths and characteristics. Unconsolidated formation could cause more serious troubles for drilling, formation evaluation, and production such as borehole washout, wellbore collapse, and sanding if proper planning is not in place. In addition, a viscous oil can add another complication for fluid sampling operations. An unsuccessful logging program could have a major impact on the field development plan (FDP) and further field investment decision (FID). In the Gulf of Thailand (GoT), high temperature Pattani basin discovery wells, reservoir fluids are mainly gas and condensate. There are numbers of waxy oil reservoirs 1 – 5 in certain area in the GoT, notably in the cooler peripheral Tertiary basins. However, the subject field is the first one that was identified as having productive heavy oil reservoirs. The viscosity variation ranges between 1 and 100 cp 2 – 6 . It was observed that there was a depth related variation with deeper reservoirs having higher viscosities, and therefore, reservoir fluid information is crucial for the FDP and FID resulting from a field extension drilling campaign in early 2018. This paper will discuss step by step (1) reservoir characterization challenges (2) proposed methods to obtain reservoir and fluid information, as well as the interval pressure transient test, (3) the actual field results, (4) recommendations and way forward for similar reservoirs. Different proposed options are also discussed with field examples to obtain high quality PVT samples. Pumping to clean up high viscous oil contaminated tends to attract finer particulates towards the probe and into the flowline, causing plugging issues in other probe types even though a modified sand filter was added. In the end, the 3D Radial probe was proven in making this exploration campaign a success story for acquiring the heaviest oil samples to date in the GoT. The 3D Radial probe equipped with mesh filter plays an important role to restrict ingress of small sand particles, thereby allowing both sustainable pumping speed and flowing pressure. The single packer design also helps to support the formation preventing drawdown collapse. Coupled with larger flow area of the probe itself, the 3D Radial Probe has ability to control flowing pressure to stay above the sand break-away pressure even as more viscous formation oil enters. However, job objectives were achieved, which were formation pressure acquisition, high-quality fluid sampling, and Interval Pressure Transient Testing (IPTT) as well as Vertical Interference Testing (VIT). This paper also discusses the comparison between Downhole Fluid Analysis results and PVT lab analyses. Limitation and challenges for downhole measurements for this heavy oil environment. Advantages and disadvantages for different testing methods for this heavy oil reservoir will also be discussed.