The strong domestic need for oil in China requires further exploration in unconventional reservoirs, such as volcanic and shale oil reservoirs. Sweet zone identification is one of the most critical missions in formation evaluation. The complex mineralogy and the low porosity in unconventional reservoirs result in little contrast of resistivities between oil-producing zones and water zones. Reducing uncertainties affecting the type of fluid in the reservoir and its potential movability is key to defining the optimal landing zones for future horizontal drains. In conventional reservoirs, nuclear magnetic resonance (NMR) logging based on cutoff analysis is the optimum choice for evaluating the porosity and pore geometry of hydrocarbon bearing reservoirs. However, the routine single-dimension T2 measurement is not sufficient for fluid typing in unconventional reservoirs because of the overlap of signals of various fluids in the T2 domain. This contribution presents case studies from a new generation NMR tool providing continuous 2D T1-T2 measurements. The T1-T2 measurements enable separation and quantification of different fluids in the pores. Fluid typing can be done by integration of other wireline logs such as spectroscopy and dielectric. Case studies are presented from volcanic and shale oil reservoirs in Xinjiang Oilfield of PetroChina. In the volcanic reservoir case, dedicated 2D data analytics technic is used to extract relevant signals from 2D NMR T1-T2 measurements. An integrated workflow combining wireline borehole electrical image, nuclear spectroscopy, dielectric dispersion and NMR T1-T2 gives an insight into the fluid composition in the pore system. Besides accurate measurements of lithology independent porosity and pore geometry from NMR, T1-T2 specific measurement of clay bound water volume and total water volume match well with the same measurements estimated from nuclear spectroscopy and dielectric dispersion logs. It lowers the uncertainties on fluid types in the volcanic reservoir where resistivities fail to differentiate wet zones and oil zones. In the shale oil reservoir case, a reservoir producibility index (RPI) derived from the integration of NMR T1-T2, wireline borehole electrical image, and nuclear spectroscopy is shown to be quite efficient in sweet zone identification and ranking. This paper discusses a novel application of a new generation NMR T1-T2 logging method in unconventional reservoirs, which helps the operator ascertain the potential of these reservoirs. The oil zones identified by the new method have promising oil productions. The workflow illustrated in the two case studies can be applied and extended to other unconventional plays in China.

Artificial intelligence (AI) has proven to be the smartest predicting tool in the oil and gas industry. In this paper, Artificial Neural Network (ANN) algorithm was applied to build two new empirical correlations to predict relative permeability profiles of oil-water two phase flow in the reservoir for both sandstone and carbonate reservoirs. The proposed model evaluates the relative permeability as a function of porosity, rock absolute permeability, initial water saturation, residual oil saturation, wettability index and water saturation. Accordingly, relative permeability to water and oil are respective outputs. Real data of both sandstone and carbonate reservoirs taken from literature were used in the development of the new empirical correlations. Multiple realizations with various hidden layer neurons were run to find the best scenario; and maximum coefficient of determination (R 2 ) was designated as the finest case. The weights and biases values were found for the models of relative permeability to water and oil after proper training and are presented in this paper. Tan-sigmoid and linear transfer functions were utilized in the hidden and output layers, respectively. Neural Network was trained using Levenberg-Marquardt back-propagation algorithm. The novel ANN model was able to accurately estimate relative permeability to oil and water for an unseen data set of 319 real data points. Root mean squared error for both models are near to zero, while R 2 for relative permeability to oil and water is 0.92 and 0.98, respectively. The relative permeability models are presented in the form of an actual mathematical correlation. The use of the developed ANN models significantly saves time and cost for conducting experiments for relative permeability measurements.

A clear description of the wettability of carbonate rocks poses numerous challenges due to its non-uniformity and uncertainty caused by complex pore systems and weak fluid/rock interactions. Aging in the crude oil and spontaneous brine imbibition of core samples in the laboratory constitute essential steps of wettability restoration, wettability measurement, and oil mobilization. Various aging durations are used to restore the carbonate wettability by researchers. The imbibed oil/water quantities in the Amott test are sometimes in the range of several percentages, and it is not clear if the fluids contact the whole core. This study investigates how the wettability evolves during again and how the imbibition develops in reservoir carbonate rocks using nuclear magnetic resonance imaging techniques. The carbonate core samples with typical multiple pore systems were first saturated with crude oil at different irreducible saturation by centrifuge and aged for different durations. Then they were immersed in deuterium oxide (D 2 O) with two ends open (TEO) at an elevated temperature for spontaneous imbibition. The aging and spontaneous imbibition processes were monitored by a 1D magnetic resonance imager either by a standard probe or a high temperature and high pressure core holder. A set of nuclear magnetic resonance measurements were conducted for any wettability alteration and oil/brine imbibition front propagations. NMR measurements during oil saturation and aging of three carbonate reservoir core samples indicate that the significant wettability change occurs after the oil flood while further aging continues to alter the wettability on a smaller scale. Low oil saturation has less of an effect on the wettability than high oil saturation. The brine imbibition fronts were found to develop from both ends or one end only, or there could be no apparent fronts. After the fronts propagate across the samples, a significant amount of brine continues to imbibe globally. The high permeability macro pore dominated samples appear to have significantly higher total brine imbibition than the low permeability micro pore dominated samples from current experimental results. Lower initial brine saturation impedes the imbibition with negligible effects on the final amount. Aging does not have appreciable effects on the brine imbibition for the samples studied. The direct observations of wettability evolution during aging and brine spatial propagation during brine imbibition by NMR under reservoir conditions provide novel information about carbonate wettability, which assists in better wettability characterization and enhanced oil mobilization by wettability alteration.

Despite intelligent method such as numerical simulation model has been used, identifying areas or zones that still holding high potential of production still becomes the most challenging aspect in the development of mature carbonate oil field with high water-cut; especially coupled with the lack of required important data to generate such appropriate model. A practical method to explore the sweet-spot areas within the field is then introduced, hereinafter called "Simulation Opportunity Index" (SOI) based on techniques already established in the industry. SOI is an integration of three (3) independent components whereas each of them is normalized to produce indexes that represent reservoir-permeability thickness, movable oil and reservoir pressure from a historically-matched dynamic model. The method utilizes the historically-matched simulation model in which the water saturation from the dynamic model is calibrated with the recent acquired cased-hole logging saturation log to improve the confidence level. The cased-hole logging saturation log results are treated as the only ground truth of the current saturation within the reservoir thus it plays important role to reduce the model uncertainty and to simplify the workflow in efficiently short time. The SOI method is hence used as an invaluable tool to spot areas for further development such as infill wells. The workflow to produce the potential areas within the reservoirs is discussed in this paper including comparison to see infill wells performance by using both conventional and SOI approaches. Notwithstanding lesser producible oil reserves due to denser-placed infill wells over time and high water-cut of the field >95%, the method after implementation in numerical simulation is capable to screen-out a number of sweet-spot areas for infill wells placement in the largest mature oil field of RH PetroGas (Basin) Ltd concession in Salawati basin, onshore West Papua, which can be ranked thereupon for execution after sensitivities and economics analysis. The infill wells are still the most technically-favourable development scheme to hold oil production decline about 6%/year in the field. Thus, it is essential to place the infill wells within the most optimum locations that would yield maximum sweep efficiency, acceleration of the expected recovery or incremental increase of the Estimated Ultimate Recovery (EUR) from such heterogeneous reservoirs. The application of SOI methodology in numerical model is helpful to practically identify areas or zones with high oil potential due to non-uniformity volumetric sweeping efficiency in carbonate reservoirs in relation to their tremendous heterogeneity, variable wettability and dual pore network.

Artificial lift is generally required to extend field-life beyond the period of natural flow. In the course of the reviews and studies we performed, we noted artificial lift had not been given sufficient consideration at initial design phase. Due to the pressure to maintain the field production, operators often choose a phased artificial lift deployment to cope with the learning curve, risks and uncertainties, which typically includes: ▪ A first phase (Phase-1) of artificial lift is screening and concept testing to evaluate artificial lift options; ▪ A second phase (Phase-2) involves deployment to a group of wells for a selected option; ▪ A final phase (Phase-3) is the full field implementation. This paper presents an efficient and effective workflow to select the most suitable candidates for Phase-2. Lessons learnt based on the implementation of workflow in real-life case studies will be shared as well: ▪ First, a well selection process is performed to review inactive strings and/or low performers that are most impacted by such issues as reservoir pressure declined / high water production. Cased-hole saturation logs (PNC log) and static pressure log measurements are used to build an understanding of areal pressure and water saturation distribution and to further identify localized pressure sinks and watered-out areas. The understanding gained upon reviewing the well-based surveillance data is used to identify candidates for artificial lift application. ▪ Then, the well candidates which are grouped by categories of issues and different reactivation options are screened for each group of wells. A score-based ranking process is applied to sort candidates on urgency, value or impact of artificial lift and possibly other criteria, using production history and surveillance data. ▪ Finally, results per well are reconsolidated to reservoir / field level and used to support a field-wide concept, which allows to extract valuable field scale requirements (e.g. the determination of the gas-lift volume requirement for gas-lift planning etc.). This workflow greately helps to understand the root cause of performance issues and to select the most suitable artificial lift concept (including considering well pre-conditioning needs such as water shut-off). It leads to exploring and defining artificial lift concepts and helps to focus on the field development plan and detail engineering study at a very early stage.

Hydrocarbon identification in mature fields located in Mahakam area is very challenging due to thin and multi layers of reservoir geometry, wide range of water salinity in deltaic environment, depletion and water-rise phenomena in highly producing zones. There are numerous possible gas reservoirs which were dubious and not included in perforation targets due to poor quality sand or risk of water production which could jeopardize the entire well potential. These possible gas reservoirs need to be re-evaluated in order to add perforation targets portfolio in maintaining field production when less new wells drilled. An integrated methodology has been continuously developed and calibrated to reduce uncertainty, hence elevate confidence level of fluid interpretation by combining the existing and recently developed techniques in Mahakam fields. The existing techniques are (1) Conventional Qualitative interpretation, (2) True-Wet Resistivity separation, and (3) Gas-Oil Volumes from simultaneous solution. The new developed techniques are (4) Swirr-SWT comparison, (5) Water Saturation Array Gradient with salinity, (6) AutoFluid resistivity specific cut-off, (7) Dual logs sliding average analysis, (8) Neutron Count Rate, (9) RT-GR cut-off, and (10) Gas Chromatograph dynamic baseline. In collaboration between petrophysicist, development geologist & reservoir engineering, this new integrated fluid interpretation methodology has been applied to re-evaluate more than 11,000 possible gas reservoirs in Mahakam fields. This effort has revealed around 32% of them as hydrocarbon potential reservoirs with total thickness of 4,195 meters. Those reservoirs are then convincingly re-interpreted as gas bearing reservoirs and included as additional perforation candidates. Some of those reservoirs have been perforated and giving additional gain in maintaining gas production of Mahakam fields. By capitalizing the existing data, with no additional data acquisition, hence no additional cost, this integrated fluid interpretation methodology, could be implemented in other fields outside Mahakam to find hidden potentials which not identified yet.

CO 2 Injection is one of the EOR methods that holds potential to be widely implemented. However, the underlying issues in implementing CO 2 injection include the availability of CO 2 sources as well as the steep capital cost associated with the surface facilities required to deliver and process the CO 2 . In such case, the cyclic injection, so-called Huff & Puff CO 2 injection is seemingly more feasible. In this study, we propose an alternative predictive model to determine the performance of CO 2 cyclic injection. This model can be utilized as a preliminary screening tool and to understand the feasibility of the operation in a quick manner. In addition, the uncertainties associated with the reservoir conditions can also be considered within the model. Most of the efforts to develop predictive model for CO 2 cyclic injection have been concentrated around empirical approach, and hence, only limited parameters are considered. In this study, we establish experimental design through reservoir simulation and perform machine learning to construct the predictive model. Therefore, most important factors driving the performance of the well underwent CO 2 cyclic injection including reservoir rock and fluid properties, interaction between rocks and fluids, drainage geometry, and operating condition are incorporated. Compared to the simulation results, the proposed predictive model shows an acceptable accuracy with R-squared of above 0.95. The result of this study can be used to help find suitable well and reservoir to be injected with cyclic CO 2 injection, as preliminary analysis on the individual well performance can be conducted before performing full field simulation. The model can also be utilized to determine the optimum amount of CO 2 needed, as well as the length of injection and soaking time before the well is put into production.

The gas content in shale reservoir is of great importance in reservoir evaluation. Shale reservoir has various gas including free gas, adsorpted gas and soluted gas. Free gas take an important part for the total gas content. Hence, we investigated three equations for water saturation calculating and compared and improved them based on theoretical analysis in order to find a siutable one for the shale reservoir characterization. The results indicate that the Archie formula has several limitations applied to complex pore structure, which leads to high water saturation. Since the Archie formula was proposed by experimental data in pure sandstone without enough consideration about the clay of shale reservoir. The Waxman-Smits is suitable to shale gas reservoirs through theoretical analysis, but there are several uncertain parameters. The conductivity of formation water is necessary parameter in calculation of formation water saturation, but calculating the conductivity of formation water is difficult in shale gas reservoir because of its intricate characterization of pore structure and conductivity. Waxman-Smits model take account for the clay conductivity, but there are several uncertain parameters which are hard to obtained, resuting high error. For instance, the equivalent conductivity of exchange cations (B) and the capacitance of exchange anions (Qv) can not be defined accurately relied on experimental calculation, which causes indefinite influence on results. Thus, we concluded that selecting the improved Indonesia equation is a better method to calculate water saturation. This study provided a comprehensive analysis and an accurate way for water satruartion evaluation in shale reservoir.

The proposed method in this paper estimates FWL based on the relationship derived between resistivity, capillary pressure, water saturation and permeability. Since porous plate experiment provides simultaneous resistivity index (RI) and capillary pressure at identical saturation state, one can combine these two pieces of information ( Pc-vs-Sw and RI-vs-Sw ) and produce a new Pc/Rt-vs-Sw plot. Interestingly, Pc/Rt-vs-Sw exhibits an exponential behavior which can be described using an exponential function with fitting coefficient a, b, c and d . Once these fitting coefficients are obtained for each individual plug, they are correlated to petrophysical property such as permeability. After all the relationships are established on core plugs, the log-based capillary pressure (P c , laboratory condition) can be estimated from the resistivity, water saturation and permeability logs. For application in oilfields, this laboratory condition Pc has to be converted to reservoir condition P c . The reservoir condition P c is interpreted as reservoir condition buoyancy pressure (P b ). We then subtract this reservoir condition P b from the hydrocarbon pressure established from the formation tester. Finally, a water line with a known gradient (eg: 0.433 psi/ft) can be drawn across the predicted log-based buoyancy pressure. FWL is located at the intersection between this ‘pseudo’ water line and hydrocarbon line established from formation tester.

Horizontal wells are superior over conventional wells in terms of production improvement due to increased reservoir contact. Despite this, these wells pose severe production challenges due to variations in permeability, reservoir pressure, reservoir fluid properties and frictional pressure drop along horizontal section. Preventing water/gas breakthrough, equalizing inflow with minimizing pressure loss, minimizing annular flow and heel-to-toe effect, delay non-uniform water progress, avoiding by-passed oil, increasing sweep efficiency and ultimate recovery are some of the primary challenges for gaining optimum advantages of horizontal wells. One of the promising technologies to address all these challenges is the application of advanced completions utilizing Passive inflow control device (ICD) with oil swellable packers. The use of Passive Inflow Control Device (ICD) along with oil swellable packer in long horizontal wells drilled in unconsolidated sandstone reservoirs has helped alleviate premature water breakthrough /high water production and sand production. Passive inflow control devices (ICDs) are effective in terms of balancing production flow and delaying the onset of water production. Nevertheless, when gas and/or water breakthrough occurs, a passive ICD will allow production of the unwanted fluid along with usual production. This paper discusses the detailed of Passive ICD design workflow and execution carried out to complete 6 nos. of horizontal wells of Oil India Limited in a reservoir having active aquifer drive considering challenges encountered due to uncertainty in permeability, water saturation, permeability distribution and saturation tables distribution. In the absence of dynamic reservoir analysis, offset well data analysis assisted in filling the data gaps by enabling geological and reservoir level understanding. The passive ICD were designed on the basis of Gamma Ray, Resistivity, NPHI (Neutron Porosity Log) and RHOB (Density Log) obtained during TLC logging. A Geological Model was constructed with certain gathered data and few Assumptions were made to obtain reservoir saturation and permeability. Moreover, in this paper an assessment is provided of the production performance review conducted over unconsolidated sandstone reservoirs developed with some horizontal wells equipped with Passive ICD completions compartmentalized with oil swellable packers versus other horizontal completions completed with conventional slotted liner completions. As drilling and completion of horizontal wells are expensive, it was critical to identify the most-suitable Passive ICD completion design with the available dataset before attempting well completion. This was addressed through a customized workflow to design and compartmentalized the horizontal section utilizing the ICD and oil swellable packers for maximizing oil recovery and water/sand breakthrough problem elimination.

Relative permeability curves in coalbed methane reservoirs (CBM), acquired by analysis of production data, can differ from laboratory-measured curves due to complications such as stress-desorption dependent permeability and cross-formational flow. This paper aims to derive relative permeability curves for coalbed methane reservoirs using production data analysis, as well as discuss curve characteristics and shapes. Field examples from the San Juan Basin in the US and the Qinshui and Ordos Basins in China are presented to provide a worldwide view of relative permeability curve shapes. These field examples are analysed using a tank type model, a common production data analysis tool, and the influential factors on curve shapes are discussed. The results and analysis indicate that permeability enhancement during the life of the well, and cross-formational flow between the coal seam and adjacent formations, can strongly control curve shapes. These effects, when not detected, can result in irregular relative permeability curve shapes obtained by analysis of production data. Direct measurement of permeability enhancement requires time-lapse production tests while investigation of cross-formational flow of water into coal seams requires hydraulic connectivity assessment, which are time consuming and expensive to conduct. The signatures of relative permeability curves presented in this study allow indirect determination of permeability enhancement and cross-formational flow in coal seam gas reservoirs.

Environmental concerns have resulted ina ban onnuclear logging-while-drilling (LWD) methods containing radioactive sources and of oil-based mud in Bohai Bay, China, which is an environmental sensitive area. To avoid the risk of a radioactive source falling into the wellbore and to keep the cost of the logging program low, nuclear magnetic resonance (NMR) LWD was used as a sourceless standalone measurement, primarily to estimate the porosity and to detect permeable intervals in the Jinzhouoilfield. This paper presents the potential and limitations of NMR-LWD in a challenging drilling environment. The resistivity of the drilling fluid was often below 0.02 ohm·m and the mud was often more than 30 K colder than the formation. These two conditions can lead to an underestimated porosity, if the NMR data is not properly corrected. Achieving rapid drilling progress was an additional goal. One borehole was drilled with a rate of penetrations (ROP) between 30 m/h and 50 m/h for analyzing the effect on data quality. The processed NMR data shows that the high ROP has no detrimental impact on the accuracy of NMR porosity results, but, as expected, the vertical resolution is directly related to the ROP. By applying the temperature and resistivity corrections, the standalone NMR-LWD measurement compares well with offset porosity based on density-neutron logging and provides reliable data for the total porosity and for all other formation evaluation applications based on NMR data. In Bohai Bay the corrected NMR data have been successfully used to accurately detect in real-time permeable intervals bearing light oil in a complex high-porosity shaly-sandstone multilayer reservoir as well as gas intervals. In addition, the NMR data have been used to quantify bound water and movable fluids and to predict the reservoir effectiveness and productivity.

The 34-X sand is a solitary sand reservoir and locally sinuous sandstone body. This reservoir is displaced by major normal fault zone known as the Widuri Fault that divided in two contrast areas of 34-X facies and production characteristic. The objective of this paper is to present how the combination drive reservoir redevelopment project was planned, extensive evaluation process has been made, and successful cases in enhancing reservoir ultimate recovery. The solution for this title is multi-disciplinary approach to create sharp analysis. The first step is numerical calculations of material balance to determine oil-in-place in a reservoir and to predict the future performance, this phase is tricky due to multi-driving mechanism reservoir behavior, therefore material balance analysis need to be supported by deep sub-surface analysis in property distribution on second step. This part simultaneous inversion, 4D timelapse seismic and sweep pattern analysis have been done to get comprehensive interpretation of reservoir characterization and reservoir connectivity monitoring. The third phase is supporting analysis by tracer injection, we implement tracer in several wells to ensure connectivity of the reservoir, and to evaluate injection performance. The last phase is technical difficulties in operation area, complex reservoir evidently cause complex operation difficulties, sand problem, formation damage, tubing leak, water out, plug-up injector well, etc. are problems we have to deal with. From reservoir pressure data distribution, surface gas-oil ratio, water production, and well behavior concludes that 34-X is combination drive reservoir (water drive-solution gas drive) and based on fault analysis we divided into two areas east and west, 34-X West area sandstone body is straight, with approximately 100-300m wide and 8m thick. The western part water cut is over 90%, this indicates the conduits for preferential water flow has established. From material balance calculation OOIP estimated 16.3 MMSTB. The eastern part of the 34-X sand appears to be isolated from western portion of the channel by a fault with a throw of 90 feet. The eastern portion of the widuri field is influenced by a partial water drive, indicated by high water cut histories. However the water drive is weak, the average pressure has declined to 520 psi, estimated OOIP 56.2 MMSTP. Before the redevelopment project recovery factor is 22%, and increase significantly to 27.4% simultaneously with oil production rate increase up to 40%. Dominantly pressure-depletion drive during hydrocarbon production in 34-X sand in west area occur since that area provide poor connection to an aquifer and for east area of Widuri Fault condition is limited aquifer. The water cut of production in 34-X sand well varies across the axis of the sandstone body, it caused by controlled by internal heteroginity.

Objectives of obtaining in-situ values of water saturation, formation water salinity, true formation resistivity (R t ) and SCAL data by core analysis can only be achieved if extraneous fluid invasion is kept at a controlled level and corrected for it or be prevented. The impossibility of zero invasion of cores by mud-filtrate makes the traced-coring a compelling method. Application of liquid based tracers such as tritium and deuterium oxide (D20) to determine the amount of fluid invasion is highly recommended in the event of critical in-situ formation properties need to be determined from core. This study presents a set of key factors for controlling invasion of core by extraneous fluids, best practices in quantifying the fluid invasion, handling core at the surface, and suggests types of analyses, specifically, for unconsolidated formations. A comparison of petrophysical parameters determined from traced-core against the results of LWD log interpretation of the same interval is also presented to assess the success/failure of the recommended practices. The main use of core-driven parameters has dual functionalities. They are used for calibrating LWD data and also are used to form a statistical database for static modeling. Calibration of LWD data with properly obtained core parameters could minimize uncertainties in calculated petrophysical parameters and establish a ground-truth in petrophysical work especially in water saturation (Sw) calculations. In our case study, good agreements are observed between log derived and core measured water saturations and salinity values extracted from the core against salinity from petrophysical study. Proper time management, core preservation technique, prompt logistical arrangements and well-site core plugging are seen as the main driving factors for a successful coring job. Comparison of fluid invasion profiles between core plugs drilled at well-site and plugs drilled later in the lab are presented to demonstrate and emphasize the importance of time-factor which constitutes the main challenge in the case study and in general. The lack of data from uncontaminated core may result in significant financial losses that may manifest itself as bypassed productive zones, erroneously determined as wet or no-production (dry) intervals, wrong completions or incorrect quantification of actual and recoverable hydrocarbons. Some of these problems are associated with lack or mismanagement of uncertainties in calculation procedures/algorithms; therefore, can be alleviated or lessened with representative and accurate core data. In addition, analyses results based on the representative core could promote better understanding of reservoir behavior and catalyze more refined reservoir management strategy. The experience acquired in this study revealed and ranked the importance of timing of the events and the procedural steps to obtain minimally invaded core plugs in a traced-core operation. Time is the most critical factor to prevent post-drill fluid-invasion and fluid re-distribution within a core which adversely impact core analysis results. Therefore, the optimum time allowed between the coring and laboratory tests, core transportation strategy, corresponding contamination of core as a function of time, recommended tests, selection of tracers and quick calculation of required tracer volume are the outputs that are elaborated in this paper. This study also highlights potential challenges in coring unconsolidated formations and serves a mitigation plan for lessening invasion of core by providing a set of recommendations for best practices.

To understand the interactions between shale rocks and aqueous drilling fluids, the spontaneous imbibition of water phase into shale pore systemsneeds to be investigated. It is important to study the shale-fluid interactions to mitigate problems associated with drilling shale formations using water-based drilling fluids. Spontaneous imbibition experiments have been frequently conducted to assess the flowback and recovery for reservoir engineering applications. In this paper, the literature has been reviewed in an attempt to link the work that has been carried out in that area to study the water filtrate invasion of drilling fluids into shale rocks while drilling. Over the years, different techniques and instruments have been used to study the spontaneous imbibition into shale rocks including: spontaneous imbibition device, which is basically analytical balance to measure the weight changes as imbibition progresses, pulse decay permeameter, scanning electron microscopy, X-ray tomography and nuclear magnetic resonance. To aid in analyzing and interpreting the results, the rocks are characterized in terms of: surface area, porosity, permeability and wettability. Fluids that have been used as the imbibing medium included: water, oil, brines, and surfactants. Three imbibition mechanisms have been revealed by literature: capillarity, osmotic diffusion, and water adsorption. These mechanisms can be distinguished when imbibed water volume is plotted against time where the imbibition rate differs for three distinct regions. Factors that were found to have impact on imbibition process include: capillary pressure, porosity, pore size distribution, pore connectivity, effective permeability, presence of fractures, bedding, mineral composition and clay content, fluid type, and properties and depositional environment (marine or continental).

Capillary pressure relationships (drainage) is of importance in both, reservoir engineering and petrophysics. Reservoir engineers use capillary pressure relationships in reservoir engineering calculations and petrophysicists use such relationships in saturation-height modelling. The overall objective of the study presented is to perform a comparative study of various capillary pressure models commonly used by the petroleum industry and to access their ability to match diverse laboratory data. Over the years many capillary pressure formulations have been proposed to match laboratory data, from the well-known Leverett J-function approach to more recent methods. Generally, formulations may be theoretical, semi-empirical, empirical or statistical basis. The comparative study presented involves the following analytical formulations: modified Leverett J-function, modified Brooks-Corey (MBC), Thomeer, Skelt-Harrison, Lambda (λ) and the more recently established, Modified Carman-Kozeny-Purcell (MCKP) model. Various types of pore structures may be modelled: homogeneous (narrow), broad (poorer sorting) and bimodal (two distinct distributions) where one of the distributions is often related to pore-fill, or a mixture of distribution types. Results presented in this paper compare application of the above-mentioned methods for homogeneous plugs. It is demonstrated that the MCKP method consistently outperforms the other methods and it is the only method that is able to identify the type of pore throat distribution without any further input data. The advantage of the MCKP method is that it does not contain any fitting parameters. The degree of accuracy of the MCKP model is typically R 2 > 0.99. The MCKP model also lends itself very easily to predict capillary pressure relationships from more basic parameters. Presented are examples with data from two Australian fields, one offshore and one onshore.

This study addresses the problem of fluid characterization in siliciclastic reservoirs where the resistivity contrast between pay and wet sands is low. Our study field contains connate water of extremely high salinity. The pay sands generally have high irreducible water saturation, which brings down the resistivity reading in oil zones. It is typically difficult to identify hydrocarbon zones with resistivity alone. The low resistivity pay poses a significant technical challenge for the development fields, because the operator must locate the by-passed hydrocarbon and understand the distribution of water floods in order to make future development plans. The key to accurate fluid characterization in this challenging environment is a good knowledge of formation water salinity. Unfortunately, due to years of water injection to maintain production pressure, water salinity in these reservoirs is highly variable. In such environments, one cannot assume a fixed salinity value when applying saturation equations to well logs. Thermal neutron cross-section (Sigma) is very sensitive to chlorine in the reservoir rocks and fluids and can be used to distinguish between water and hydrocarbon in a salty water environment. Since both Sigma and resistivity are dictated by water salinity, we can use these two inputs to simultaneously invert for the two unknowns, water saturation ( S w ) and water salinity. This process avoids interpretation errors caused by uncertainty in water salinity and does a good job distinguishing bypassed hydrocarbon from water zones. Furthermore, we can use the inverted S w and salinity to compute continuous hydrocarbon density, hydrogen index (HI) and viscosity downhole. We applied the above technique to a set of LWD logs acquired in 4 horizontal development wells. We validated our computed water saturation with production history of these wells. The hydrocarbon fluids parameters, ie, salinity, density, HI and viscosity, are cross-checked with surface measurements on produced fluids.

The characterization of high clay volume reservoirs is a challenge in terms of cut-offs determination, saturation modeling, and simulation setup. These can be even more complicated when it incorporates zero water production from the transition zone. In transition zone, both hydrocarbon and water are expected to move. However, dry hydrocarbon production from transition zone is a common phenomenon observed in many parts of the world. Modular Formation Dynamic Tester (MDT) and Drill Stem Test (DST) in three (3) appraisal wells in a high clay volume sandstone reservoir show no evidence of water production in spite of the long perforation interval just above the contact. This could be explained by different reasons depending on the type of reservoir lithology and mineralogy. One of the common reasons in sandstone reservoirs including this case is the presence of Smectite clay mineral in shale, which can immobilize large amount of water. There are many challenges in characterization and modeling of this high clay volume, dry producing gas reservoir. For instance, how to estimate the amount of mobile and immobile water saturation in the transition zone, how to incorporate the capillary pressure (Pc) data in simulation while still maintaining the production performance, and whether or not the potential reserve and flow characteristics can be captured if petrophysical cut-off applied into the model. This paper will illustrate the case study in characterizing and building the dynamic model with immobile water in transition zone whereas the mentioned challenges are addressed. A novel method is presented to construct the model to estimate the total immobile water saturation using core and log data, and different approaches to initialize the model while evaluating the impact of Pc on reservoir performance are also further discussed.

History matching and production optimization are the important keys in reservoir modeling. Reservoir geology plays a crucial role in these complicated processes and the oil and gas operators highly demand for a fast, accurate and effective integration of geology and reservoir engineering that is still limited in the past. This paper aims to present: (1) a modeling approach that automatically integrates geological modeling software, a reservoir simulator, and history matching and optimization software in a closed-loop; (2) the advantages of an assisted history matching approach; (3) a robust optimization workflow based on multiple geological realizations. This new approach was successfully applied in a Brugge reservoir. We first present a systematical workflow of the integrated modeling that allows us to capture the crucial effects of geology. Based on this approach, multiple geological realizations are geostatiscally generated for history matching, robust optimization and uncertainty assessment. We utilize the benefits of coupling the geological modeling software, the reservoir simulator and the optimization tool together. The Designed Exploration and Controlled Evolution optimization method is used to perform the history matching. In the history matching process, the optimizer invokes geological software with new variogram parameters to calculate the reservoir properties. Finally, a robust optimization approach based on multiple geological realizations is introduced to overcome the current weakness of optimization based on single realization. The closed loop modeling approach is proven a powerful tool to improve the modeling quality and reduce the time and engineering efforts for capturing the critical effects of reservoir geology in complex sandstone reservoirs. Using this closed loop modeling, we successfully perform an assisted history matching of the secondary waterflooding process. This method effectively accounts for the uncertainty of geological characteristics in terms of facies proportion and spatial distribution. The properties of each facies were controlled by both blocked data histograms and the vertical trend. The results of history matching show that the misfit of objective functions was reduced from 16.45% to 6%. Finally, we optimize the rates of thirty injection and production wells over the life of a reservoir, with the objective to maximize the average NPV based on the geological realizations that the history misfit is less than 7% rather than using a single realization. The results show that the robust optimization significantly improve the expected NPV and reduce substantially the risk associated with geological uncertainties. This paper presents an efficient modeling and optimization approach under geological uncertainties by integrating various simulator's available in the industry. The innovative closed loop modeling workflow together with an assisted history matching and robust optimization provides a means of optimizing recovery and assessing uncertainties of both secondary and tertiary EOR processes.

It is generally believed that the incomplete return of treating fluids (flowback) is a reason for the failure of hydraulic fracturing and it is associated with poor gas production. Capillary effects and fracture face skin are known to be the main parameters that limit flowback in tight gas sands. However, near-wellbore pressure loss during the main operation of hydraulic fracturing and its effects on flowback are not well understood. In the case of pre-existing natural fractures in a reservoir, near-wellbore pressure loss is high mainly because multiple fractures with tortuous paths are often created. Also, it is believed that this tortuous path causes shear dilation in natural fractures and opens the closed fractures. As a result, there is a large amount of pressure dependent leakoff. Therefore, pressure dependent leakoff has both positive and negative impacts. It can increase rock permeability and at the same time it can cause a high near-wellbore pressure drop. Hence, near-wellbore pressure needs to be reduced in order to have better proppant placement and maximize the fracturing fluid flowback. For this research, several hydraulic fracturing treatments in the Patchawarra formation in the Cooper Basin, South Australia have been studied. There are some pre-existing natural fractures in our case study. The bottom-hole treating pressure has been analysed with 600 psi of near-wellbore pressure loss causing a low percentage of proppant placement. We constructed a 3D hydraulic fracturing model coupled with multiphase flow simulation for the prediction of flowback of water and gas production. Several injection fall-off tests were first interpreted and found that the leakoff is pressure dependent. Our simulation has shown that high near-wellbore pressure loss has an impact on the effectiveness of the fracture treatment. This results in a shorter fracture length and low pressure distribution inside the fracture that leads to a low recovery of fracturing fluid. As a result, we have successfully provided recommendations for best practice to reduce near-wellbore pressure loss.