Condensate banking in natural gas reservoirs can hinder the productivity of production wells dramatically due to the multiphase flow behaviour around the wellbore. This phenomenon takes place when the reservoir pressure drops below the dew point pressure. In this work, we model this occurrence and investigate how the injection of CO 2 can enhance the well productivity using novel discretization and linearization schemes such as mimetic finite difference and operator-based linearization from an in-house built compositional reservoir simulator. The injection of CO 2 as an enhanced recovery technique is chosen to assess its value as a potential remedy to reduce carbon emissions associated with natural gas production. First, we model a base case with a single producer where we show the deposition of condensate banking around the well and the decline of pressure and production with time. In another case, we inject CO 2 into the reservoir as an enhanced gas recovery mechanism. In both cases, we use fully tensor permeability and unstructured tetrahedral grids using mimetic finite difference (MFD) method. The results of the simulation show that the gas and condensate production rates drop after a certain production plateau, specifically the drop in the condensate rate by up to 46%. The introduction of a CO 2 injector yields a positive impact on the productivity and pressure decline of the well, delaying the plateau by up to 1.5 years. It also improves the productivity index by above 35% on both the gas and condensate performance, thus reducing production rate loss on both gas and condensate by over 8% and the pressure, while in terms of pressure and drawdown, an improvement of 2.9 to 19.6% is observed per year.

The increasing atmospheric concentration of carbon dioxide (CO 2 ), a greenhouse gas (GHG) is creating environmental imbalance and affecting the climate adversely due to growing industrialization. Global leaders are emphasizing on controlling the production of GHG. However, growing demands of natural gas, industry is embarking on the development of high CO 2 contaminant gas fields to meet supply gap. Development and management of contaminated hydrocarbon gas fields add additional dimension of sequestration of CO 2 after production and separation in project management. CO 2 sequestration is a process for eternity with a possibility of zero-degree failure. Monitoring, measuring and verification (MMV) of injected CO 2 volume in sequestration is critical component along with geological site selection, transportation, storage process. The present study discusses all the impacting parameters which makes whole process environment friendly, economically prudent and adhering to national and international regulations. The migration of injected CO 2 plume in the reservoir is uncertain and its monitoring is equally challenging. The role of MMV planning is critical in development of high CO 2 contaminant fields of offshore Sarawak. It substantiates that injected CO 2 in the reservoir is intact and safely stored for hundreds of years after injection and possesses minimum to no risk to HS&E. The deployment of Multi-Fiber Optic Sensor System (M-FOSS) promises a cost-effective solution for monitoring the lateral & vertical migration of CO 2 plume by acquiring 4D DAS-VSP (Distributed Acoustic Sensor – Vertical Seismic Profile) survey and for the well integrity by analyzing DAS/DTS (Distributed Temperature Sensor)/DPS (Distributed Pressure Sensor)/DSS (Distributed Strain Sensor) data. Simulation results and injectivity test at laboratory for in-situ CO 2 injection has demonstrated the possibility of over 100MMscfd/well injection in aquifer to meet the total CO 2 injection of 1.2Bscfd for full field development while maintaining the reservoir integrity. Uncertainty & risk analysis shows possible presence of seismically undistinguished fractures and minor faults, an early breakthrough of injected CO 2 cannot be ruled out. The depleted reservoir storage study divulges the containment capacity of identified carbonate reservoirs as well as conformance of potential storage sites. The fault-seal analysis and reservoir integrity studies determine the robustness of the long-term security of the CO 2 storage. Injectivity study demonstrates the optimum and maximum possible rates of CO 2 injection into these depleted gas reservoirs. VSP simulation results show that a subsurface coverage of 3-4 km 2 per well is achievable, which along with simulated CO 2 plume extent help to determine the number of wells required to get maximum monitoring coverage for the MMV planning. The deployment of M-FOSS technology is novel and proactive approach to monitor the CO 2 plume migration and well integrity. First ever development of MMV Planning for CO 2 Sequestration in offshore Sarawak, Malaysia using novel and cutting-edge M-FOSS technology for proactive monitoring of CO 2 plume migration and well integrity.

Quantification of the end-point oil saturation of the relative permeability curves is an essential part of building a reliable simulation model to better capture the flow dynamics. A key challenge is to reduce measurement uncertainties and overcome technology limitations. Particularly for water flooded heterogeneous reservoirs with mixed salinity environment, it is vital to combine multiple sources of oil saturation measurements to substantiate end-point results. In this paper, a new workflow is established to estimate the oil end-point oil saturation by integrating specialized logging and core analysis techniques. This workflow examines data collected from both ends of a reservoir's scale spectrum that represent macro and micro scales, ranging from field in-situ electrical logging to plug-size lab experiments. The dataset incorporates oil saturation data acquired from sponge coring, centrifuge test, dielectric log, and carbon-oxygen log. The oil saturation data are clustered based on a set of petrophysical hydraulic flow units. The data sufficiency and quality are evaluated from the statistical analysis of the distribution profiles. The high uncertainty measurements are filtered out for spurious points and also for the log results that are beyond the tools' threshold. The saturation data collected from different logging and coring methods are compared per rock type. Despite the variety of scale and techniques used, the workflow yields consistent results. The centrifuge test is used as the primary source of the end-point oil saturation. For hydraulic units with low reservoir quality, sponge core results are used to derive end-point oil saturation in the absence of centrifuge data. Additionally, in-situ saturation data derived from dielectric and carbon-oxygen logs are in a close agreement to sponge core data, which are used to corroborate the derived end-point oil saturations. The approach highlighted in this work can be used as a benchmark for future studies. There is no unique practice in the oil industry for the determination of the end-point oil saturation and there are very few comprehensive studies in the literature. The workflow presented here is validated by implementation to a diverse dataset, which is used to characterize relative permeability curves in the reservoir simulation model.

Enhanced Oil Recovery (EOR) strategies are becoming increasingly common in the Middle East, used primarily for increasing recovery factors from mature fields. The final location, selected for any EOR scheme, is often critical to its ultimate success and developing new methods to investigate the most optimal EOR schemes can add significant value in optimizing recovery from mature fields. One approach for a given field, is to subdivide 3D Geo-cellular models into different sectors and perform a statistical analysis of the 3D model's properties (porosity, permeability, saturations, etc.) in each individual sector. This task is usually performed manually and can be resource intensive and time-consuming. In particular, in the case of large mature fields in the Middle East, the scale and data volume involved often makes the workflow impractical to implement. Advanced ‘automation methods’, developed to rapidly generate EOR sectors and perform the statistical analysis of 3D model properties are therefore necessary. This work presents a new workflow implemented for extracting and analyzing model properties at a scale relevant for EOR planning in large scale Middle East Fields.

Considering the oil prices hovering at low levels, opportunities to reduce the cost and enhance productivities becomes the new routine, to improve the net present value, and reduce operating cost. Field A is located offshore West Malaysia with production started in 1960's. Idle or uneconomic producing wells went through detailed study to identify and appraise possible behind casing opportunities prior to plug and abandon. The detailed assessment targeted to verify hydrocarbon-bearing sands, in reservoirs known to be fine to very fine and interbedded silts and clays layers. To identify the present behind casing hydrocarbon saturation, and assess reservoir depletion, advanced pulsed neutron capture surveillance is used in the low contrast reservoir. A combination of elastic and inelastic pulse neutron logging, supplemented with total organic carbon (TOC) was carried out. TOC, Sigma, and near to far detectors were used to ascertain the presence of hydrocarbon. Results were compared to the open-hole saturation to identify possible depletion, and differentiate it from annulus-trapped hydrocarbon. Completion was cemented and considered as a new casing. Two self-oriented perforation runs were carried out in each interval to ensure penetrating the two casings into the reservoir. Results coming from pulsed neutron capture indicated presence of HC in various reservoirs; these results were cross-confirmed by sigma and carbon/oxygen logging. TOC computed oil volume is compared to the CO yields computed oil volume, and Sigma derived saturation to identify water bearing zones. Fluid typing was carried out to confirm the fluid properties are not changed. Contradicting results were looked into and verified. Sigma derived saturation was found to be influenced by complex lithology patterns such as carbonate and coal streaks. False HC indications such as behind annulus trapped oil and gas were identified using combination of thermal and burst rations with far and deep late capture curves. Redistributed saturation lead to firming new opportunities that were not considered earlier. Identified prospects were later categorized, and further allocated between long and short strings to minimize depletion and maximize well potential. Tubing annulus is cemented to ensure zonal isolation and ensure well integrity, as a result, two runs of perforations were planned for each interval to increase depth of penetration and improve productivity. The use of all available data allowed to derisk planned perforations and add additional resources. The developed workflow enlightens the best practice to budgetary recomplete low producing offshore wells. The niche low cost data acquisition, and assessment maximized and ascertained reservoir potential and ensure all available opportunities are looked into without being misled by late well life completion, cementation problems accumulated over time. The followed workflow ensured booking the additional reserves and allowed bringing well back to life at low cost.

The amount and type of clays in reservoirs have a significant impact on formation evaluation and reservoir performance studies. Currently, clay typing requires either reservoir cores for laboratory analysis or advanced logs such as elemental spectral mineralogy logs, both are available in only a small fraction of wells drilled. In this study, we will explore a possibility of using commonly measured logs to estimate clay volumes. Specifically, the logs used for the study are formation resistivity (RT), total porosity (PHIT) and gamma ray (GR). Since there are no known relationships relating these logs with clay volume, machine learning has been used for data analysis and parameter prediction. This is followed by exploring the possibilities of using array induction resistivity measurements to classify clay types downhole. An important property of clay minerals is their ability to adsorb ions on their exposed surface, which is measured by its cation exchange capacity (CEC). We have developed a method of using induction resistivity data to extract CEC downhole and displayed as depth profiles. There are four major types of clays commonly encountered in the oil fields: Kaolinite, Chlorite, Illite, and Smectite, with their CEC values ranging from low to high. Since each type of clay has its own CEC value, thus a synthetic CEC depth profile for any clay can be constructed if its volume fraction is known. On the other hand, CEC derived from the downhole resistivity data represents the combined effects of all the clay types presented in the formation being surveyed. By comparing the resistivity-based CEC profile with the synthetic ones, it is possible to define a volume fraction for each clay type, for the purpose of clay typing. On the other hand, based on a previous developed method, total CEC representing the combined effects of all clays can be extracted from induction resistivity logs. By comparing the resistivity-based measured total CEC with the synthetic type curves, clay typing from downhole induction resistivity measurement is achieved. A workflow is developed for the application. The proposed methodology was tested on the logs from six wells. The results indicated that RT, PHIT and GR logs have strong correlations with clay volume and the model trained with these logs could be used to predict clay volumes for blind datasets. The workflow for clay typing was tested on the logs from two wells with positive results.

After the successful pilot (18%STOOIP incremental oil, Juri et al. 2017 and utility factor of 1,76 kg polymer/bbl) of two technologies, continuous polymer injection 0.3PV followed by high frequency water-alternate-polymer 0.3PV, a series of multiple simulations cases indicated an optimal extension of 3-year cycle -0.4 to 0.6PV- factory mode development. Despite all advantages of polymer injection, few full-field expansions emerge from many challenges in integrating multiple disciplines -lab studies, subsurface reservoir modelling, engineering, energy, procurement, logistics, storage, project management- all parties find it difficult focusing on a common goal and streamline the decision process. Because it has long been thought that the EOR road map means planning for large scale EOR. However, that is false because there are very few full-field injections. The past strategy in EOR has led to a few pilot extensions implemented. Planning for large-scale EOR suffers from having the incremental oil, uncertainty in oil price, uncertainty in economic drivers and uncertainty in technical solutions for the expansion on the same time frame, which undermines economics. What it seems to be the only way to make progress with EOR, in reality, is that EOR should align with planning for quick oil response. We present here the steps to accelerate EOR in Grimbeek field from a 4-injectors pilot to 80 new injectors in a fast, less than 18 months deployment. We compare the capital and operating cost of multiple expansion scenarios. The scope is to accelerate EOR deployment opposite to the slow typical EOR workflow. We have seen the opportunity in accelerating the oil focusing on a simple modular strategy rather than iterating multiple possible engineering solutions to distribute the polymer across the field. NPV of the overall project is higher than the costs of delaying the injection or having to redo parts of the implementation along the deployment. Future optimisation is necessary for options of logistics, storage, in-situ skid connection and mounting along with by-pass remote control valves and remote control of skid injections. The building blocks of the strategy are containerised mobile skids containing ten pumps, polymer dispersion unit, and 30-metric ton silos. The mobile skids plug-in the waterflooding manifolds in an easy and fast connection. This injection scheme distributes polymer using the already implemented waterflooding in-situ installation. We focus on having a simple, standard and mobile system targeting fast implementation and fast oil response rather than large facilities.

Two-phase immiscible drainage experiments are performed on strongly water-wet sandstone sample to assess and illustrate capillary end effects at different rates on relative permeability. All the experiments were done under unsteady state conditions with oil displacing brine in fully brine saturated cores. First, relative permeability curves are calculated using the Johnson–Bossler–Naumann (JBN) method ( Johnson et al. 1959 ). Then, modified JBN model is defined to account for capillary pressure. Lastly, numerical simulator is used to generate relative permeability curves based on history matching. Results of the experiments show that as the rate increases (higher capillary number), the water relative permeability increases while the irreducible water saturation decreases. With high rate, less water saturation is being accumulated at the outlet hence less irreducible water and higher relative permeability. Moreover, the oil relative permeability curves are getting higher with higher rates confirming CEE impact on the tests. The calculated irreducible water saturation based on the core weights re-affirms the JBN calculation and decreases with higher rates. This paper proves capillary end effects on relative permeability curves at low rates which have low capillary numbers on water-wet sandstone cores.

The occurrence of Low Resistivity Pay (LRP) have been widely reported. The conventional induction resistivity log does not recognized LRP, because this phenomenon affects the conventional resistivity log to read lower response. This problem typically occurs because of the shoulder effect of shale laminae on resistivity measurements of oil saturated sand intervals and as a result, conventional petro-physical interpretations would be unable to identify pay intervals in such low-resistivity measurements. Conventional well log evaluation usually considers these intervals water-bearing (60-70%) interval, which completely conceal oil occurrence. Numerous case studies showed water-free oil production from low resistivity laminated reservoirs. When these laminations thickness are less than the vertical resolution of conventional resistivity measuring device itself, the measured resistivity values is no longer representative to these laminations, however it becomes an average of the resistivity of these thin laminations, dominated by the laminations with lower resistivity. These apparent average values of resistivity curves may mask the recognition of hydrocarbon presence. This formation evaluation challenge is usually addressed using simultaneous measurements of horizontal (Rh) and vertical (Rv) resistivity measurements. Such measurements are not conventionally used and therefore unconventional interpretation would be impossible or at least difficult. In the present paper, an innovative technique is developed to calculate the resistivity of sand intervals within thin laminated reservoirs from conventional apparent resistivity measurements and lithology logs. This is achieved considering two main concepts; separating apparent resistivity in Rh and Rv using Moran and Gianzero (1979) formula and calculating sand resistivity using sand - shale resistivity connections (parallel and series connections). In North Morgan Belayiem reservoir located in the Gulf of Suez in Egypt, which was discovered since 1965, a new detailed interpretation and formation evaluation analysis have been done to re-interpret thin sand shale laminations having low conventional resistivity curves. Pay was identified using Rv and Rh calculations in petro-physical interpretation instead of using pervious conventional resistivity and lithology logs. After validating the petro-physical analysis and making an integration with available production data, the potential of the LRP zones in this reservoir was confirmed and quantified using petro-physical attribute.

In rich gas fields, condensate banking refers to the formation of condensate around the wellbore when the reservoir pressure drops below dew point. Condensate banking severely damages reservoir performance and results in loss of production capacity and ultimate recovery, especially for reservoirs with low permeability and high Condensate Gas Ratios. Understanding this process and quantifying its impact is therefore crucial to robust field development projects economics and effective well and reservoir management. The characterization of condensate banking is an integrated process where several reservoir parameters like fluid properties (PVT), geology (i.e. permeability), and rock properties (i.e. SCAL data) needs to be considered. Because of condensate banking, different flow regions with different characteristics are created within the reservoir where Pressure Transient Analysis (PTA) can identify these flow regions. This study attempts to characterize the condensate banking using PTA, shows examples of pitfalls in well test analysis of rich condensate fields and provides the methods proposed to identify condensation effect in PTA analysis. In order to detect, quantify and characterize condensate banking, a workflow was developed using PTA along with other field data (PVT/SCAL/production). The process to define this workflow includes; Conducting a review of critical parameters affecting the condensate banking process (PVT, SCAL, reservoir properties…. etc.), Collecting and interpreting all PTA’s (51) from 5 large gas condensate fields to understand the condensation process characteristics in terms of PTA diagnostics (i.e. determine the mobility change in the reservoir) Developing a novel integrated workflow and procedures for condensate banking characterization and quantification using Inflow Performance Curves (IPR). The key conclusions of integrated approach are follows; PVT (maximum condensate drop out), SCAL (Krg & Ng) and permeability plays a critical role for condensation effect Several PTA interpretations demonstrated that the expected 3 mobility regions associated to condensation effect may not able to be seen due to near wellbore & reservoir effects (i.e. wellbore storage, fraccing) that has been masking the condensation response, Even in case of hydraulically fracced well, condensation will still negatively affect the well performance. None of 5 field cases has shown any indication of a "capillary number effect" (i.e. velocity dependent relative permeability) IPR is proposed and used to quantify the impact of condensation drop out on production performance. An integrated workflow to detect, quantify and characterize condensate banking using PTA analysis has been developed and implemented in five large PDO gas condensate fields. This paper presents a novel systematic approach to achieve Condensate Banking Characterization Using PTA for gas condensate reservoirs as well as it provides several real cases to validate the workflow. Results can also contribute to a better reservoir management, quantification of the possible productivity losses of the well.

A new analytical procedure is introduced for the interpretation of pressure-transient data in oil producers with pronounced water production. The new mathematical model is applicable to flow conditions where segregated flow dominates the displacement process in the reservoir. Here, formation flow capacity and individual magnitudes of oil- and water-phase mobility are also determined, allowing accurate reservoir characterization under such complex flow conditions. Segregated flow is very common in natural porous rocks and is characterized by a sharp interface between oil and water. Hence, our new mathematical model mimics the dynamics of this flow mechanism by taking into consideration the individual contributions of oil and water from each reservoir zone. This novel mathematical model is utilized to extract formation flow capacity and mobility for both phases. An average fluid saturation can also be determined with a reasonable accuracy. The reservoir system in hand is represented by a two-layer model with no crossflow between the different zones in the reservoir. Because of gravity effects, oil is produced from the top layer while water is produced from the bottom one. Each reservoir layer has its own distinct static and dynamic properties, such as porosity, permeability, thickness, and petrophysical properties. A case study based on synthetic reservoir data is presented to demonstrate the application of the mathematical model in characterizing formation rocks. It is observed that conventional well-testing methods could produce inaccurate results when applied to reservoir systems influenced by segregated flow. Using the new model, a correction factor is derived to estimate absolute permeability values from the conventional well-testing analysis, producing a one-to-one transformation between dispersed and segregated flow. The conventional way of interpreting pressure-transient data for two-phase flow displacements under segregated conditions is based on an equivalent single-phase flow model that might produce inaccurate results and invalid estimates of flow capacity and phase mobility. Our new approach, therefore, is more representative for the system under consideration and captures the flow mechanism more robustly.

Enhanced oil recovery (EOR) processes may often involve simultaneous flow of two or three immiscible fluids inside the reservoir. A precise evaluation of relative permeabilities is critical to quantify multi-phase flow dynamics, assisting improved management and development of oil- and gas- bearing formations. This study illustrates the results of laboratory-scale investigations of multiphase flow on a sandstone reservoir core sample to evaluate relative permeabilities under two- and three-phase (i.e., water, oil, and gas) conditions. We use the ensuing information to simulate WAG injection at reservoir scale. The experiments are conducted at high temperature, consistent with reservoir conditions, to obtain two- (oil/water and oil/gas) and three-phase (oil/water/gas) relative permeabilities through Steady-State (SS) technique. Our laboratory workflow allows for an improved investigation by combining coreflooding experiments with in-situ X-Ray evaluation of local saturation distribution. The latter technique permits to asses slice-averaged phase saturation along the rock core, enabling to compute saturation profiles and average saturations while flooding, thus yielding significant advantages over traditional methodologies based on mass balance. Three-phase steady state (SS) experiments are performed by following diverse saturation paths, and the complete experimental dataset is provided to ( a ) assess the occurrence of local three-phase saturation conditions and ( b ) possibly investigate hysteretic effects of relative permeabilities. We evaluate three-phase relative permeabilities across the entire three-phase saturation region by leveraging a Sigmoid-based model ( Ranaee et al., 2015 ). The resulting set of experimental two- and three-phase coreflooding results constitute a unique dataset which is then employed for reservoir simulation studies mimicking WAG injection and results are discussed in comparison with reservoir production under a waterflooding scenario.

Interval pressure transient tests (IPTT) are commonly used in the industry to obtain permeability distribution along the wellbore. Despite the remarkable progress achieved in IPTT analysis in last two decades, interpretation of IPTT is still unclear if test interval consists of oil zone with vertically connected transition zone and water aquifer. One easy and common approach for interpreting such data is to assume that oil zone, transition zone, and water aquifer as a distinct zone and then perform non-linear regression to measured IPTT pressure data set using single phase layer cake model. In this approach, due to the single-phase nature of the model, capillary pressure and relative permeability effects are totally ignored, however, it is assumed that water saturation data is available from log analysis and saturation weighted viscosity value represents the transition zone. As expected, it is determined only effective horizontal and vertical permeability values from this analysis rather than absolute permeability. It is also important to highlight that reliable effective permeability data is estimated solely in the zone where a test is performed. In fact, accurate prediction well and reservoir performance require values of absolute permeability information. As a second approach to analyze IPTT data, it is assumed that water saturation, relative permeability, and capillary pressure data are known parameters and optimization technique is used based on numerical reservoir simulation to estimate absolute permeability values. Like the previous case, horizontal and vertical permeability values are reliably obtained only in the zone where a test is performed. The only difference with the previous approach is that estimated permeability values are absolute permeability values rather than effective permeability. In practice in IPTT jobs, water cut is generally measured with pressure data in various depths in the transition zone to fine tune free water level. It is also important to note that relative permeability and capillary pressure data are not always available before IPTT interpretation. As a last approach in this study, both pressure and water cut data are simultaneously used in the optimization to find each zone’s horizontal and vertical permeability values, relative permeability and capillary pressure curves. Fairly satisfactory estimations are obtained from simultaneous regression of water cut and pressure data obtained from IPTT.

Secondary oil recovery by waterflooding is usually achieved in neutrally and water wet reservoirs. Special core analysis (SCAL) data are difficult to obtain and expensive, we therefore generate experimentally-derived petrophysical correlations based on SCAL experiments conducted on neutrally wet sandstone in order to further understand maximizing oil recovery. The key objectives of the present study are to obtain and analyze the possible relationships between the reservoir petrophysical properties that are essential for reservoir simulations. The experimentally obtained petrophysical parameters and generated relationships are compared versus the prevailing initial water saturation, absolute permeability and wettability. Experimental results are then compared with network modeling results from the literature. Network modeling is a promising tool that has many usages including the convenient estimation of capillary pressure, relative permeability and residual oil saturation that would otherwise be obtained through lengthy and expensive SCAL experiments. However, network modeling predictively has been questioned in terms of making a full priori prediction of multiphase flow properties in mixed and neutrally wet systems as true representation of pore geometry and wettability are most challenging. Scaled, two-phase oil-water system, endpoint relative permeability was found to be linearly and strongly correlated to wettability. Residual oil saturation, however, was found to be curvilinear upward correlated to Amott-Harvey wettability. Comparing the experimental results of the present study with previous network model results, limited agreement was observed. Disagreement was mainly due to pore space wettability misrepresentation in network models. The representation of neutral wettability is the path towards more realistic physical description of pore-scale multiphase flow since most reservoirs tend to show some degree of neutral wettability.

Aiming to improve the characterization of Carbonate Reservoirs from resource assessment to optimization of the static and dynamic modeling, we describe a holistic flowchart for an integrated approach by using the capillary pressure measurements. Its most innovative steps from pore scale to field scale is illustrated on a Super Giant Carbonate Reservoir from the Middle East. The flowchart relies on patented, published and proven "data driven" algorithmic techniques (k-NN, Histogram Upscaling and MRGC-CFSOM clustering) devoid of any user’s bias. Its capability to integrate Static and Dynamic, from Pore Scale to Log scale, stems from the integration, prediction and upscaling at log scale, over cored and un-cored intervals of MICP curves together with all core and log material. Predictions by means of "k-NN multiple modeling" of SCAL & RCA plug measurements allows a reliable and accurate characterization of the rock matrix at log scale, while quantifying its degree of heterogeneity. By revealing to the geoscientists, the pore scale rock texture, its stratigraphic evolution and its heterogeneities, the continuous profile of upscaled Pore Size Distribution (PSD) curves vs logs provides invaluable information on the rock forming processes controlling the matrix Porous Network. By applying the Purcell theory onto the upscaled PSD, the "Log scale" Permeability and the true FZI and R mh are computed which are then used as input to a e-Facies model (MRGC-CFSOM) by integrating to other logs and core material. The e-Facies model is interpreted in terms of "matrix" storage and flow parameters as well as in terms of depositional mechanisms and diagenetic overprints, in the light of the core descriptions whose Petrophysical pertinence is thoroughly and quantitatively validated with all the Petrophysical material. By reversing the method used to derive PSD from MICP saturation curves and using the Pc equating the buoyancy forces at any depth increment, the saturation at any depth increment above the actual Free Water Level (or a scenario of FWL), is computed from the continuous profile of upscaled PSD. Production data, RSTs and PLTS provide the information on total flow and by subtracting matrix contribution to the total flow, the location and quantification of the contribution of the depth intervals with large vugs and fractures is greatly eased, particularly if Borehole imagery is available. The contribution of Matrix, large vugs and fractures are then merged into a single model used for robust well to well correlations, zonation of the reservoir, 3D gridding and volumetric evaluation. Using this innovative flowchart approach, characterization of high permeability streaks, saturation height function and chemical polymer EOR processes were greatly improved as input to the static and dynamic model history match exercise.

A series of petrohysical experiments have been conducted to obtain the gas physical properties (e.g., gas-water interfacial tension). The capillary pressures of pore throats were obtained through numerical calculation. Furthermore, residue water was used to calculate gas/water saturation in the reservoirs. The gas saturation variation under lower interfacial tension and the amount of gas lost during the uplift in burial history need an in-depth examination ( Tian et al., 2017 ). In addition to the geological studies in the field, various laboratory methods were used to tackle the problems mentioned above, including Nlear nuclear magnetic resonance (NMR) and fluid inclusion analysis with optical and Laser Raman spectroscopy. During the charging history, hydrcarbon saturations at different temperature and pressure was calculated using the model established in this paper, which is mainly determined by the pore size distribution obtained by the NMR analysis. The charging pressure is measured by fluid inclusion study with optical and Laser Raman spectroscopy test. Furthermore, the leakage content of gas during the burial history was calculated using a diffusion model ( Krooss& Leythaeuser., 1988 ; Krooss et al., 1992 ).

The Naturally Fractured Reservoirs (NFR) constitute a challenge for the oil industry due to its importance in hydrocarbon production and the technical complexity they represent, because well’s productivity in carbonated formations is influenced by fracture systems that govern the fluids motion within reservoirs. This approach is oriented to the analysis of a very complex NFR, where we show the results obtained through a dynamic characterization methodology focused on new opportunities in a High Pressure-High Temperature (HP-HT) coastal mature oilfield with high water cut production. The proposed methodology is based on a full analysis starting from the pressure-production historical data, fluids properties, dual-porosity material balance, a detailed static model update (petrophysics, core analysis, petrography, fracture analysis, sedimentology-diagenesis and structural geology), flow units discretization, Water-Oil Contact (WOC) advance monitoring in each block, Pressure Transient Analysis (PTA) (determination of preferential flow direction and interference), and Rate Transient Analysis (RTA). This methodology allowed to determine the real Original Oil in Place (OOIP) and the proper recovery factor according to the type of NFR and its characteristics, to detect different WOC’s for each block that were hydraulically connected to each other but with a different dynamic behavior among them, the detection of heterogeneities, facies changes and faults that originally were not mapped, sweet spots location, better distribution of the petrophysical properties, fracture analysis, static model reinterpretation based on the dynamic behavior, reservoir connectivity analysis (among blocks) and the generation of improved production forecasts based on an exploitation strategy especially designed for the current conditions and needs of the field; all of this contributed to have a better understanding of the reservoir and a good numerical simulation model.

Building realistic and reliable subsurface models requires detailed knowledge of both the rock and fluids involved. While the hydrocarbon volume estimation has a profound impact on the viability of a development, next to the saturation height models and free fluid levels the hydraulic communication and permeability have a significant role as well. Compartmentalization could change the field development plan: e.g. increase the well count, necessitate significant change to the well profiles (e.g. extended range drilling), require complex and expensive completion strategy. When in different parts of the same field different free fluid levels are identified, leading to different fluid contacts for the same rock quality, the lateral hydraulic communication at the field level can be challenged. This aspect is of importance since the hydrocarbon volume distribution has drastic impact on total hydrocarbon recovery. At the same time building and initializing a model based on different free water level positions across the field, zero capillary pressure, is challenging. Perched water contacts are the result of water entrapment during the hydrocarbon migration that could lead to variability in free fluid levels across a field. The fundamental controls that lead to the perched contacts formation are studied and shown to be the rock quality and relative permeability. Counter-intuitively, the perching effect is not going to feature in poor quality rocks with sub-milli Darcy permeability – the effects would be visible only for a considerable barrier height, with Free Water Level to barrier height of tensto hundred meters. In addition, realistic heterogeneous models are studied to investigate the heterogeneity effect on perching and on formation pressures. Whilst low permeability is correlated to a wide range of depths where two phases are mobile, the perching controls in high permeability contrast formations are studied. Using a dynamic modelling route, potential water entrapment occurrence as a result of high permeability contrast is shown, without structural control, i.e. an underlying impermeably zone defining a trap. The main control in such a case is water permeability just as in structurally controlled perching. This work challenges the industry view that model initialization should be performed with buoyancy as an equilibrium driving mechanism. Such a saturation modelling route would lead to discrepancies when compared to using the capillary pressure as a direct input instead of buoyancy.

Data acquisition remains one of the crucial activities to be consistently executed throughout field life for any oilfield development. Significant operating expenditure (OPEX) is allocated each year to understand reservoir performance, thus reduce uncertainties and enable optimizations. This paper aims to highlight the issues faced during simulation model history matching (HM) process of a waterflood reservoir, including understanding of depositional environment and production data integrity. The output is utilized to improve recovery factor (RF) via infill opportunities and water injection optimization. Field A has run a second shot of 3D seismic in 2006 (first in 1995) and processed into a time lapse, 4D seismic. In 2014, a cased hole logging campaign utilizing the high precision temperature, spectral noise logging (HPT-SNL) tool has been completed to check the integrity and flow contribution of 12 wells in Reservoir-X. Within the same period, a pulse pressure testing (PPT) was carried out to verify the communication between wells, in addition to acquiring regular surveillance data which helped to improve reservoir simulation study. The 4D seismic helped to understand the areal waterflood front movement and explained the water cut trend anomaly in an updip well which experienced earlier water breakthrough than near downdip producers. Moreover, it helped to identify a bypass oil zone which can potentially be an infill location. As most of the wells are on dual string completion, the HPT-SNL campaign helped to improve production allocation of multi stacked reservoirs as well as identify problematic wells which required rectification jobs. The PPT assisted in identifying a baffle zone to explain the poor pressure support observed in some producers in the south from the nearby water injectors. All data interpretations were incorporated into final HM model which subsequently identified infill locations and the reservoir management plan (RMP) was successfully revised. An infill program was executed in 2015, which successfully secured additional EUR of ~9 MMstb. Based on the studies and outcome of the infill campaign water injection optimization helped to improve production and added ~2 MMstb reserves, through voidage replacement ratio (VRR) optimization and oil producer (OP) to water injector (WI) conversion. With these efforts, team could successfully project RF of >55%. This case study demonstrates how acquiring focused surveillance data and their effective integration in performance analysis in simulation study helps to reduce uncertainties, unveils infill opportunities, improves production injection optimization and thus helps to improve the recovery factor in brown fields.

It is a common practice to run a contact-saturation log to confirm the oil column prior to oil gain activities such as adding perforations or infill drilling. From 2012 to 2017, a total of eight logging jobs were executed in Field B which were subsequently followed by oil gain activities. The eight contact-saturation logging jobs were comprised of pulse-neutron logs in both carbon-oxygen (C/O) and sigma mode. The logs were run in varied well completions targeting thirteen different zones. Four logs were run in single tubing strings while the remaining four were in dual string completions. Certain target zones were already perforated while others had completion accessories such as a blast joint or integrated tubing-conveyed perforating (iTCP) guns across them. Eight of the target zones were later add-perforated while two were used to mature infill well targets. Four of the seven add-perforations results were consistent with the logging results. One of the successful logs clearly indicated that the oil column had migrated into the original gas cap. Of the two infill wells drilled, only one was successful. These case studies in Field B indicate that in conditions of open perforations, trapped fluid across the annulus, and in low resistivity sand, distinguishing between original and residual saturation is difficult with pulse-neutron log. The log measurement was significantly affected. The most obvious lesson learned was that perforating and producing the reservoir would be the best method to confirm the potential oil gain. From a value point of view, it would have been more economical to perforate the zone straightaway if the oil gain activity had similar cost to the logging activity. The lessons learned also helped to establish clear guidelines in Field B on utilizing contact-saturation logs in the future. The paper seeks to present the logging results, subsequent oil gain activities, and lessons learned from the contact-saturation logging in Field B. These lessons learned will be applicable in other oilfields with similar conditions to improve decision making in the industry.