NotesNov-09NOTES:The papers listed here have been obtained by search SPE and IPTC papers post 2005 on the SPE's OnePetroThe papers relating to reservoir engineering have been catergorised for inclusion on the reservoirengineering.org.uk websiteThe affiiations searched were;Total No PapersReservoir Engineering RelatedBP551175Shell575279Chevron482238ConocoPhillips19168Marathon5537Total255129Schlumberger1130563Imperial College, London9553Heriot Watt University, Edinburgh235175(Anywhere in Article)Total35691717Total number of papers published post 2005 =10,00035% of papers published categorised

Reservoir PerformanceOrganisationSourcePaper No.ChapterSectionSubjectTitleAuthorAbstractCHEVRONSPE100209Reservoir PerformanceBreakthrough ProfilingTemperature EffectPrediction of Temperature Changes Caused by Water or Gas Entry Into a Horizontal WellK. Yoshioka, Chevron ETC; D. Zhu, and A.D. Hill, Texas A&M University; P. Dawkrajai, Thailand Defense Energy Department; and L. W. Lake, University of Texas at AustinSummary With the recent development of temperature measurement systems such as fiber-optic distributed temperature sensors continuous temperature profiles in a horizontal well can be obtained with high precision. Small temperature changes with a resolution on the order of 0.1F can be detected by modern temperature-measuring instruments in intelligent completions which may aid the diagnosis of downhole flow conditions. Since in a producing horizontal well fluid inflowing temperature is not affected by elevational geothermal temperature changes the primary temperature differences for each phase (oil water and gas) are caused by frictional effects. While gas production usually causes a temperature decrease water entry results in either warming or cooling of the wellbore. Warmer water entry is a result of water flow from a warmer aquifer below the producing zone (water coning). In contrast produced water can be cooler than produced oil because of differences in the thermal properties of these fluids. If both oil and water are produced from the same elevation oil is heated more by friction while flowing in a porous medium than water is resulting in the produced water having a lower inflow temperature than the oil. Water entry by coning is relatively easy to detect from the temperature profile because of its warmer inflow temperature but water breakthrough from the same elevation as the oil may not be obvious. In this paper we illustrate the range of inflow conditions for which water-or-gas entry locations can be identified from the temperature profile of a wellfrom measurable temperature changes. Using a numerical wellbore-temperature-prediction model (Yoshioka et al. 2005a) we calculated temperature profiles for a wide range of water-inflow conditions.In these calculations we assumed that one section of the well produced water or gas while the rest of the open section of the well produced oil. From sensitivity studies we showed the predictions of the relative water-and-gas production rates that create detectable temperature anomalies in the temperature profile along the well. By using the model to match an actual temperature log from a horizontal well we demonstrate how this model can be used to identify water-inflow locations. Introduction Temperature logs have been used to locate water entries. Some field examples (Tolan et al. 2001; Foucault et al. 2004) reported the successful identification of water entry and prevention of its further production. However the identification is often made by intuition. That is gas entries reduce the wellbore temperature and water entries increase the temperature. The inferences are also qualitative. There is no means to determine the rate of water entry for example. To optimize well performance we need a better method to identify water or gas entries. We will analyze anomalous temperature changes along a flowing horizontal well using a temperature model for horizontal wells. The main difference of the model from the vertical thermal wellbore models (Hill 1990; Ramey 1962; Sagar et al. 1991) is that the geothermal temperature is constant along a horizontal well. Temperature deviations from the geothermal temperature are caused by changes in flow conditions in the reservoir and wellbore. If we assume that all the fluids in the wellbore are produced from the same elevation (i.e. the temperatures are the same at the boundary) the reservoir energy balance can be solved as a 1D problem. To infer the temperature behavior with water coning the problem needs to be solved in 3D (Dawkrajai et al. 2006). The detailed discussions of the prediction model are in the following section. Model Description We have used two different models in this study. For water produced from the same elevation as the oil we consider a segmented reservoir and multiphase flow in the wellbore. We also consider a steady-state reservoir with constant fluxes from both sides and no flow at the other boundaries (Fig. 1). For water coning a 3D reservoir model is used (Fig. 2). The top and sides of the rectangular reservoir are sealed and the pressure below the reservoir (the aquifer pressure) is constant. In both cases we assumed fully penetrating horizontal wellbores. For nonisothermal flow we can derive the mass-and-energy balance equations for the reservoir and wellbore. The solution of the coupled reservoir and wellbore equations provides the temperature and pressure profiles in the domain of interest.TOTALIPTC11369Reservoir PerformanceCarbonate ReservoirsIntegrated StudyAl Khalij: The Quest For Oil In A Highly Complex Carbonate FieldDavid Foulon, SPE, Total E&P Qatar; Florence Viban, Total E&P France, Rashed Noman, SPE, Qatar Petroleum, Bernard Faissat, SPE, Total E&P Qatar, Ismail A. Al-Emadi, SPE, Qatar PetroleumAbstract Al Khalij could be viewed as the archetypal complex carbonate field. Laterally sealed by a stratigraphic closure the reservoir monocline consists in a layercake of alternating good and poor quality rock whose fabric has been intensively reworked during multiple phases of diagenesis. Additionally the oil column is relatively thin and average water saturation above free water level exceeds 85%. Al Khalij development challenge can thus be formulated as: How to efficiently recover a large oil accumulation trapped with much larger amounts of water in the capillary transition zone of a highly heterogeneous reservoir of uncertain boundaries overlying an active aquifer?" To meet a challenge of such magnitude a phased development was undertaken and completed recently nine years after kick-off. Even so the expected recovery factor remained low and the reservoir model unmatched. This paper describes the extensive work program implemented to better understand early-time reservoir behavior and find ways to increase recovery. Starting with a "back to the rocks" approach a wide range of studies and additional measurements were undertaken culminating in full field reservoir simulations. Innovative modeling and interpretation techniques were implemented to extract maximum information from formation pressure and pressure build-up measurements. Where key uncertainties remained specific solutions were sought in terms of enhanced data acquisition and monitoring programs from petrophysical measurements on full size cores to injection PLTs in oil producers. Integrated static and dynamic syntheses reviewed all resulting information to better assess critical reservoir heterogeneity levels. A specifically designed dual-porosity simulation model was built to properly represent the smallscale heterogeneity impact and successfully history matched. In less than two years a full field redevelopment plan was defined that is expected to double the recovery factor. The innovative acquisition interpretation and modeling techniques developed in the process could fruitfully be applied to other complex fields. Introduction Al Khalij field operated by Total is located 110 km offshore Qatar within the Block 6 with a water depth of approximately 60 m. The field was discovered in 1991 after the interpretation of 2D seismic acquired in 1989 and developed in a phased way through horizontal wells since 1997. The field being marginally eruptive production wells are activated by a wide range of centrifugal pumps. The increasing knowledge gathered on the field has lead to reassess its potential since exploration time leading to a stabilized oil production plateau since 2005. Al Khalij reservoir presents some striking features (Ref. 1 2). It is quite wide (some 250+ km2) and thin (in most areas under 50 m) monocline (Fig. 1). Oil-bearing reservoirs are Cenomanian limestones of the Mishrif formation capped by Turonian Laffan shales. These carbonates were deposited in a shallow shelf environment and range from lagoonal muddy deposits to Rudist shoal facies. The uppermost part of the reservoir series is partially eroded as a consequence of a regional uplift of the platform northwards. Moreover the monoclinal trap reveals a stratigraphic component as a lateral seal is provided by muddy deposits developed westwards. The resulting rock structure is a layer cake of matrix low-permeability (circa 10 mD) and average porosity (circa 20%) carbonates alternated with drain high permeability (in the Darcy range) and high porosity (circa 30%) ones with pressure communication throughout the different units (Fig. 2). It is filled with fluids mainly in the capillary transition zone with water above WOC considered mobile (Fig. 3). Finally in terms of production it exhibits good well productivities but a production behavior marked by both a fast water breakthrough and steady pressure depletion in the wells drainage area."SHELLIPTC11722Reservoir PerformanceCharacterisation and ModellingCarbonate reservoirImproved Characterisation and Modelling of Carbonate Reservoirs for Predicting Waterflood PerformanceS.K. Masalmeh and X.D. Jing, Shell Technology OmanAbstract Carbonate reservoirs are highly heterogeneous and often show oil-wet or mixed-wet characteristics. Both geological heterogeneity and wettability have strong impact on capillary pressure (Pc) and relative permeability (Kr) behaviour which is controlled by the pore size distribution interfacial tension and interactions between rock and fluids as well as the saturation history. Capillary pressure data are essential input in both static and dynamic modelling of heterogeneous carbonate reservoirs. Drainage Pc is generally used for initialising reservoir static models while imbibition Pc is used to model secondary and tertiary recovery processes. The objective of this paper is to present an improved reservoir characterisation and modelling procedure for predicting waterflood performance of a Cretaceous carbonate reservoir in the Middle East. We focus on the characterisation of multi-phase fluid flow properties in particular the capillary pressure characteristics in both drainage and imbibition and their assignments in reservoir simulation models. We show that for modelling initial saturation distribution in the reservoir assigning saturation functions based on permeability or porosity classes alone is not adequate. Moreover the petrophysical correlations often used for clastic reservoirs (e.g. Leverett J-function) may not be applicable to carbonate reservoirs without careful pore-type examination and core analysis/calibration. A novel procedure is described to derive imbibition capillary pressure curves from the primary drainage Pc curves taking into account of wettability and fluid trapping. The results lead to an improved understanding of capillary pressure characteristics in carbonate reservoirs in particular the contact angle distributions and hysteresis behaviour in both drainage and imbibition. This paper also presents a mathematical model for implementing both drainage and imbibition capillary pressure functions in dynamic reservoir simulation. This model takes into account the complex pore size distribution and wettability characteristics in carbonates as observed in experimental special core analysis (SCAL) measurements. Furthermore how to assign imbibition Pc for the different porosity and permeability classes will be examined and its impact on modelling waterflooding performance and remaining oil saturation distributions assessed. Introduction The complexity of carbonate reservoirs and the importance of a consistent approach in defining rock types have been a subject of several recent papers (Marzouk et al. 2000; Ramakrishnam et. al. 2000; Leal et. al. 2001; Porrai and Campos 2001; Giot et.al 2000; Silva et.al. 2002; Hamon 2002; Masalmeh and Jing 2004). Current practices in general are either based on petrophysical properties (i.e. porosity permeability and drainage Pc curves) or geological description (facies and depositional environment) or a combination of both. The underlying assumption is that static rock characterisation and the resultant rock-typing scheme remain valid when assigning saturation functions (Pc & Kr) in dynamic reservoir modelling. In this paper we will incorporate conventional core analysis (porosity permeability) thin section and SEM analysis mercury-air capillary pressure (Pc)/ NMR with special core analysis data in particular the imbibition Pc and residual oil saturation. Several experimental techniques are available to measure capillary pressure (Pc) curves both in drainage and imbibition cycles. Mercury injection is frequently used for measuring drainage Pc curves as the technique is relatively cheap fast and requires relatively straightforward data interpretation. The measured data however need to be converted to in situ reservoir conditions by taking into account the differences in interfacial tension and contact angle between the rock/fluid systems used in the laboratory and that found in reservoir. The porous-plate equilibrium method is a reliable and accurate technique for measuring Pc in drainage and imbibition under representative reservoir conditions of fluids pressure and temperature. The main drawback of this technique is the lengthy time required to reach capillary equilibrium which renders the technique impractical for certain field applications especially for tight and heterogeneous carbonates. The multi-speed centrifuge method can be used for both drainage and imbibition Pc measurements using representative reservoir fluids. Compared with the porous-plate equilibrium technique the centrifuge method is relatively fast which is a clear advantage for studying tight carbonates. However the design of the centrifuge experiment and the interpretation of the data are not straightforward and numerical simulation of centrifuge experiments is generally required to derive capillary pressure data (Maas and Schulte 1997).SHELLSPE113865Reservoir PerformanceComplex ReservoirsJG FieldReservoir Compartmentalisation in the JG Field Western Desert EgyptEilard H. Hoogerduijn Strating, SPE, and Willem Postuma, Shell International Exploration and ProductionAbstract The JG field is located in the North East Abu Gharadig (NEAG) Basin of the Western Desert in Egypt. With first production in 2002 it is the first commercial discovery in the Middle Jurassic Lower Safa Reservoir Units in this basin. Oil and gas are produced from the tidally influenced estuary channel deposits in the Lower Safa A Unit and oil from the massive braided fluvial channels in the Lower Safa C Unit. At first the field was believed to consist of one single hydrocarbon column. However based on production behavior and additional well information it became apparent that the field was highly compartmentalized in the vertical and horizontal domain. Since then multiple data sources have been leveraged in order to obtain better compartment definitions: 3D seismic logs PVT data geochemical fingerprinting repeat pressure surveys and production data. The boundaries between the reservoir compartments are defined by a combination of faults and stratigraphic heterogeneities. Although clear in places some compartment boundaries can only be defined from non-geological data sources. Understanding these heterogeneities and compartment boundaries is essential for optimizing the field development. Like so many fields the JG field proved to be more complex than initially expected. It is argued that extensive data gathering in particular in the early field development is essential in helping to timely identify and properly define such complexities. Introduction The Abu Gharadig basin in the Western Desert of Egypt (Fig 1) was generally considered to be a mature basin with over 95% of the oil and gas fields in Upper Cretaceous Abu Roash Bahariya and Kharita sandstone reservoirs. Shell Egypt N.V. (52% (operator) Apache 48%) however continued to explore for deeper targets in its North East Abu Gharadig Exploration License in particular in the Jurassic Safa sandstones overlying the Paleozoic basement (Fig. 2). This perseverance paid of with the 2001 NEAG JG-1 well which at a depth of 3 250 mbdf found three oil-bearing channel sands in the tidally influenced estuary deposits of the Lower Safa A. A 6m net (20ft) oil-bearing channel sand tested 4 100 bbl/d of 36API oil with a 1 300 scf/bbl GOR (Ref 1). The JG discovery was brought on production in 2002 and as such constitutes the first commercial discovery in the Lower Safa Reservoir Units in the Abu Gharadig basin. Including the discovery well a total of 9 wells and one sidetrack have been drilled to date (Fig 3). The information of these wells in combination with production and well and reservoir surveillance data significantly improved the understanding of the field. At first the field was believed to consist of one single hydrocarbon column that in places also extended into the massive braided fluvial channels in the Lower Safa C Unit. However with time it became apparent that the field was highly compartmentalized in the vertical and horizontal domain. Since then multiple data sources have been leveraged in order to obtain better compartment definitions: logs RFTs PVT samples geochemical fingerprinting of oil samples repeat pressure surveys and production data. The boundaries between the reservoir compartments are defined by a combination of faults and stratigraphic heterogeneities. Although clear in places some compartment boundaries can only be defined from non-geological data sources. Understanding these heterogeneities and compartment boundaries is essential for optimizing the field development vis--vis different depletion rates drive mechanism and production optimization. This paper builds upon earlier published work1 but will focus in more detail on the reservoir compartmentalization issues. In particular it will discuss the data sources used interpretation and integration of the data definition of the compartment boundaries and the impact on field development.Heriot Watt UniversitySPE113394Reservoir PerformanceDepressuriziationFluid MobilityEffect of Depressurization on Trapped Saturations and Fluid Flow FunctionsA.N. Nyre, CIPR and IFT/University of Bergen; S.R. McDougall, Heriot-Watt University; and A. Skauge, CIPR/University of BergenAbstract Production below bubblepoint will generate free gas first as discontinuous gas up to the critical gas saturation and thereafter free or mobile gas. The level of critical gas saturation is affected by pressure decline rate interfacial tensions pore structure etc. The gas relative permeability is strongly reduced when trapped gas is present. Recent experimental studies have proved that gas relative permeability can be several orders of magnitude lower for an internal gas drive process (gas liberation during depressurization) than for an external gas drive process (gas injection). The critical gas saturation may indirectly influence gas breakthrough gas cut and also oil production. Network modeling has been used to investigate physical relations to factors influencing the formation of critical gas saturation and the corresponding flow functions. The rock matrix composition determines together with irreducible water saturation diffusion paths and therefore the degree of supersaturation in the medium. This mechanism combined with depletion rates describes how trapped and mobile gas saturation evolves and determines factors influencing critical gas saturation. We observe that bubble generation is strongly dependent on depletion rate which in turn affects the critical gas saturation. The gas relative permeability is found to be two orders of magnitude lower than for gas injection even at relatively high gas saturations. We discuss the importance of including the physics of depressurization and advice on correct implementation of depressurization in reservoir simulations. The results show that lower coordination number leads to higher critical gas saturation. The variation of critical gas saturation with pore structure diminishes at higher depletion rate. The significance to field application of depletion is that near the production well the pore structure has little influence on the critical gas saturation while at low depletion rate in the reservoir (far from the well) the pore structure may be an important factor for the critical gas saturation. Introduction Studies of production below bubblepoint have been conducted in a variety of ways ranging from core depletion experiments with internal drive gas drive or combined internal and external gas drive. As the mechanisms of gas bubble formation and expansion of the gas phase are difficult to investigate in detail in a porous medium the effect of pressure depletion below bubblepoint has also been studied by network modeling. Depletion below bubblepoint involves many coupled mechanisms and therefore there is still a lot to gain by improving the process understanding. Some key elements are the complexity of gas liberation and kinetic processes such as bubble nucleation diffusion supersaturation and in addition to fluid properties and the effects of capillary/gravitational/viscous force balance. Critical gas saturation (Sgc) is one of the parameters that have been extensively investigated. There are several ways of defining critical gas saturation in solution drive experiments. In an experimental setup where monitoring pore-scale processes is difficult the critical gas saturation has been defined as the saturation at which gas is first detected (Firoozabadi et al. 1992). Another definition is; the saturation at which the producing gas-oil ratio exceeds the solution gas-oil ratio (Sahni et al. 2001). For network modeling purposes the best definition is achieved by relating critical gas saturation to percolation theory. The gas saturation at which a gas cluster spans the network is the saturation where a continuous gas flow can be first observed and of course this coincides with a non-zero relative permeability for gas consequently this is the critical gas saturation (as suggested by Yortsos and Parlar 1989).Heriot Watt UniversitySPE107164Reservoir PerformanceFault ReactivationCoupled Reservoir/Geomechanical ModelIdentification of Activated (Therefore Potentially Conductive) Faults and Fractures Through Statistical Correlations in Production and Injection Rates and Coupled FlowGeomechanical ModellingKes Heffer, Reservoir Dynamics Ltd.; Xing Zhang and Nick Koutsabeloulis, VIPS Ltd.; and Ian Main and Lun Li, U. of EdinburghAbstract Long-range stress-related and fault-related characteristics of correlations in fluctuations in flow-rates are explained conceptually in the context of the lithospheres near-critical mechanical state and a strong feedback between deformation and local permeability. A more sophisticated statistical model devised to extract a parsimonious set of flow-rate correlations has shown similar characteristics. Coupled geomechanical-flow modeling was able to reproduce those characteristics for a generic pattern waterflood perturbed with random noise but only when loaded to a near-critical state hence providing strong support for the conceptual model. Coupled modeling of a cross-section representative of the Gullfaks field also demonstrated long-range influences. The matrix of empirical correlations between all well-pairs for a field can be decomposed in various ways. The principal components of the matrix when interpolated with appropriate spatial correlation functions have indicated the importance of particular faults in the rate fluctuation history; it is inferred that those faults are mechanically active during the development and thus are potentially conductive features. Introduction It is usually assumed that geomechanical modelling coupled with reservoir simulation is only required in a minor subset of reservoirs that are termed stress-sensitive. This subset is sometimes recognized a posteriori; i.e. during the course of field development often through a general severe decline in permeability levels with depleting pressure; or perhaps a priori in the case of weak reservoir rocks where compaction drive is considered important to recovery (e.g. unconsolidated sands or weak chalks). Rarely outside such bounds is geomechanical modelling deemed necessary for reliable unbiased reservoir performance predictions. However some past analyses of preferred directions of flooding1 2 and of the correlations in rate fluctuations3 have suggested that geomechanics may be playing a commercially significant role in many secondary and tertiary floods if not other development schemes. Key to the interpretation of this field data are the following concepts which may be novel to many reservoir engineers or geoscientists: Much of the lithosphere is in a near-critical statee.g.4 5. This means that there are percolating paths of faults fractures and incipient fractures that are near mechanical failure in the prevailing stress states. This concept is supported by direct measurements of stress state6 7 observations of (micro-)seismicity induced by oilfield development8 shear-wave splitting observed in most types of rock in the crust9 and the observations of so-called 1/f scaling of properties in well-logs10. These observations are themselves underpinned by theoretical explanations of the evolution of the earths lithosphere into a near-critical state. Such models include self-organized criticality (SOC)4 11-15; or self-organized sub-criticality16-19; or in the sense of a spinodal critical point20. Whilst there is still ongoing discussion as to which of these models best fits lithospheric deformation common characteristics of these theories also observed in the real behaviour of rock are: Strong susceptibility to small perturbation (metastability) Responses often at a distance from perturbing load (long-range correlation) Percolating paths of incipient failure (localization) oriented in association with the modern-day stress state. CHEVRONSPE114909Reservoir PerformanceFault ReactivationSteamfloodingSteam Flooding Field Fault Reactivation Maximum Reservoir Pressure Prediction Using Deterministic and Probabilistic ApproachesX. Yi, Chevron CorporationAbstract Fault reactivation induced by excessive reservoir steam pressure in heavy oil fields is suspected as one of the possible perpetrators that caused steam eruption to the surface. This can lead to significant financial losses related to environment cleanup and curtailed oil production. A traditional approach to fault reactivation prediction provides a deterministic critical reservoir pressure without proper regard to the uncertainties in the model input parameters and the predicted results. A probability distribution of the fault reactivation maximum reservoir pressure provides a better means to calculate a risk weighted Expected Net Present Value for management to make better decisions on steam flooding and to anticipate potential consequences. In this study a geomechanical model was established for the Batang Field Central Sumatra Indonesia. Using the geomechanical model first a fault seal analysis was performed and indicated that all faults were sealed in sands under initial stress and pore pressure conditions. Second fault reactivation reservoir pressures for major faults in the field were predicted assuming a frictional sliding frictional coefficient of 0.5 which was derived using frictional faulting theory by a geomechanics services provider for the nearby Duri Field. Two scenarios were run in this case. One assumed a stress path coefficient of zero for horizontal stresses (decoupled); the other assumed a stress path coefficient of 0.4 (coupled). It was found that the coupling of stress and reservoir pressure provides a less conservative value of maximum reservoir pressure. Lastly Monte Carlo simulations were run to consider the uncertainties of frictional sliding coefficient and especially the stress path coefficient among the input parameters. It was found that the results from Monte Carlo simulations and deterministic approach were largely consistent but the resulting probability distribution from the Monte Carlo simulation approach provides significantly more information. Introduction Batang is a heavy oil field located in Central Sumatra Indonesia just north of the giant Duri Field (Figure 1). It is heavily faulted and compartmentalized (Figure 2). Currently the field has more than 60 wells producing from reservoirs at depths varying from about 100 ft to nearly 700 ft TVD. Huff-and-puff is being used on a single well basis to improve heavy oil production. The Batang asset team was considering whether to add pattern steam flooding to this field. Since steam eruption had occurred in the nearby Duri field causing significant environmental problems and curtailed well production the Batang team was interested in knowing how to properly operate the steam injection wells to reduce the chance of steam eruption to surface. According to the Duri field experiences many of the steam eruptions were related to faults in addition to other factors such as poor cementing jobs [1]. In this study it was also assumed that elevated reservoir pressure due to steam injection may cause a fault cutting through a reservoir to be reactivated causing steam eruption to surface either directly along the fault plane or indirectly by first entering shallower low pressure reservoirs and then flowing through the gap between the cement sheath and formation. Using this assumption a maximum reservoir pressure without reactivating a fault was predicted and provided to the Batang team for steam flooding design. To achieve that first a geomechanical model needed to be established. Using the geomechanical model and the orientation of a specific fault a normal stress and a shear stress on the fault plane were resolved [2]. Together with a Coulomb failure envelope a critical reservoir pressure was calculated.CHEVRONSPE92973Reservoir PerformanceHeterogeneityStatistical Moment EquationsConditional Statistical Moment Equations for Dynamic Data Integration in Heterogeneous ReservoirsLiyong Li, SPE, Chevron, and Hamdi A. Tchelepi, SPE, Stanford U.Summary An inversion method for the integration of dynamic (pressure) data directly into statistical moment equations (SMEs) is presented. The method is demonstrated for incompressible flow in heterogeneous reservoirs. In addition to information about the mean variance and correlation structure of the permeability few permeability measurements are assumed available. Moreover few measurements of the dependent variable are available. The first two statistical moments of the dependent variable (pressure) are conditioned on all available information directly. An iterative inversion scheme is used to integrate the pressure data into the conditional statistical moment equations (CSMEs). That is the available information is used to condition or improve the estimates of the first two moments of permeability pressure and velocity directly. This is different from Monte Carlo (MC) -based geostatistical inversion techniques where conditioning on dynamic data is performed for one realization of the permeability field at a time. In the MC approach estimates of the prediction uncertainty are obtained from statistical post-processing of a large number of inversions one per realization. Several examples of flow in heterogeneous domains in a quarter-five-spot setting are used to demonstrate the CSME-based method. We found that as the number of pressure measurements increases the conditional mean pressure becomes more spatially variable while the conditional pressure variance gets smaller. Iteration of the CSME inversion loop is necessary only when the number of pressure measurements is large. Use of the CSME simulator to assess the value of information in terms of its impact on prediction uncertainty is also presented. Introduction The properties of natural geologic formations (e.g. permeability) rarely display uniformity or smoothness. Instead they usually show significant variability and complex patterns of correlation. The detailed spatial distributions of reservoir properties such as permeability are needed to make performance predictions using numerical reservoir simulation. Unfortunately only limited data are available for the construction of these detailed reservoir-description models. Consequently our incomplete knowledge (uncertainty) about the property distributions in these highly complex natural geologic systems means that significant uncertainty accompanies predictions of reservoir flow performance. To deal with the problem of characterizing reservoir properties that exhibit such variability and complexity of spatial correlation patterns when only limited data are available a probabilistic framework is commonly used. In this framework the reservoir properties (e.g. permeability) are assumed to be a random space function. As a result flow-related properties such as pressure velocity and saturations are random functions. We assume that the available information about the permeability field includes a few measurements in addition to the spatial correlation structure which we take here as the two-point covariance. This incomplete knowledge (uncertainty) about the detailed spatial distribution of permeability is the only source of uncertainty in our problem. Uncertainty about the detailed distribution of the permeability field in the reservoir leads to uncertainty in the computed predictions of the flow field (e.g. pressure).CHEVRONSPE122357Reservoir PerformanceMechanismAcid BreakthroughModels and Methods for Understanding of Early Acid Breakthrough Observed in Acid Core-floods of Vuggy CarbonatesO.Izgec, D.Zhu, A.D.Hill, SPE, Texas A&M UniversityAbstract Previously we have studied the acidization of vuggy carbonates with acid core flood experiments in 4-inch diameter by 20-inch long cores high resolution computerized tomography imaging image processing and geostatistical characterization. The obvious major finding from these tests is that acid propagates wormholes through vuggy carbonates much more rapidly than occurs in more homogeneous rocks. Acid-created wormholes were observed to break through to the end of the cores an order of magnitude more rapidly than occurs in more homogeneous cores highlighting the necessity of understanding the flow and transport in vuggy carbonates. The fact that acid channeled through the vugular cores following the path of the vug system was underlined with computerized tomography scans of the cores before and after acid injection. This observation proposes that local pressure drops created by vugs are more dominant in determining the wormhole flow path than the chemical reactions occurring at the pore level. Following this idea we are presenting a modeling study in order to understand flow in porous media in the presence of vugs. Use of coupled Darcy and Stokes flow principles known as the Darcy-Brinkman formulation underpins the proposed approach. The power of the Darcy-Brinkman formulation lies in its natural ability to represent both porous media and tube flow in a single equation with variable coefficients. The methods presented here shows that acid injected into vuggy limestones follows a preferential pathway guided by the vug network. The PVbt (pore volumes to break through) for vuggy limestone correlates inversely with the fraction of total porosity comprised by vugs the higher the vuggy fraction of porosity the lower the pore volumes to breakthrough. Local pressure drops created by vugs are more dominant in determining the wormhole flow path than the chemical reactions occurring at the pore level. The results from the developed model demonstrate that the total injection volume to breakthrough is affected by the spatial distribution the amount and the connectivity of vuggy pore space. Introduction Matrix acidizing is a technique that has been used extensively since the 1930s to improve production from oil and gas wells and to improve injection into injection wells. Matrix stimulation is accomplished by injecting a fluid (e.g. acid or solvent) to dissolve and/or disperse materials that impair well production in sandstones or to create new unimpaired flow channels between the wellbore and a carbonate formation. The principle of a matrix acidizing treatment in carbonate reservoir is to bypass near well-bore damaged region by creating highly conductive channels known as wormholes. When the reaction rate is rapid the larger pores tend to grow much more rapidly than do the smaller ones. This gives rise to a phenomenon known as wormholing in which a few large holes form and conduct all or nearly all of the acid (Schechter 1992). The success of the stimulation depends on the ability of the engineer to control the unstable process creating the wormholes. Studies show that more than 35% of matrix treatment failed or did not reach expectations (Sengul and Remisio 2002). In some cases excessive water production was reported because of an inappropriate design. Another consequence of inappropriate design is pore collapse because of the over treatment. Optimized design gains much more attention when horizontal wells come to picture. Since the volume of acid to stimulate these wells is huge a well designed acid treatment plan has great importance.SHELLSPE113429Reservoir PerformanceMechanismDispersionInvestigation of Field Scale DispersionAbraham K. John, SPE, Larry W. Lake, SPE, Steven L. Bryant, SPE, and James W. Jennings, SPE, The University of Texas at AustinAbstract Dispersivity data compiled over many lengths show that values at typical interwell distances are about two to four factors of ten larger than those measured on cores. Such large dispersivities may represent significant mixing in the reservoir or they may be a result of convective spreading driven by permeability heterogeneity. The work in this paper uses the idea of flow reversal to resolve the ambiguity between convective spreading and mixing. We simulate flow reversal tests for tracer transport in several permeability realizations using particle tracking simulations (free from numerical dispersion) on three-dimensional high resolution models at the field scale. We show that convective spreading even without local mixing can result in dispersion-like mixing zone growth with large dispersivities because of permeability heterogeneity. But for such cases the dispersivity estimated on flow reversal is zero. With local mixing (diffusion or core scale dispersion) the dispersivity value on flow reversal is non-zero and also much larger than typical core values. Layering in permeability while increasing the convective contribution to transport also enhances mixing by providing larger area in the transverse direction for diffusion to act. This suggests that in-situ mixing is an important phenomenon affecting the transport of solutes in permeable media even at large scales. Dispersivity values increase with scale mainly because of the increase in the correlation in the permeability field but they could also apparently appear to do so because the Fickian model fails to capture the mixing zone growth correctly at early times. The results and approach shown here could be used to differentiate between displacement and sweep efficiency in field scale displacements to ensure accurate representation of dispersive mixing in reservoir simulation and to guide upscaling workflows. The flow reversal concept motivates a new line of inquiry for lab and field scale experiments. 1. Introduction Dispersion is the in-situ mixing of chemical components as they are transported through porous media. It results from the combined effects of molecular diffusion and fluid velocity gradients (Taylor 1953). The recovery efficiency of processes like miscible gas or chemical flooding depends partly on the mixing which an injected slug undergoes. For example Solano et al. (2001) performing a range of one dimensional and two dimensional simulations of enriched gas floods show that the recovery difference between the cases studied could be up to 8% of the original oil in place depending on the degree of dispersion. Similar observations have been made by others (Haajizadeh et al. 1998; Jessen et al. 2002; Moulds et al. 2005). Dispersion is also an important effect in water injection where mineral scales are formed by mixing of injected and reservoir brines (Sorbie and MacKay 2000; Delshad and Pope 2003) in the underground storage of gases where mixing of the injected and in-situ gas changes the quality of the stored gas (Verlaan 1998) and in proposed methods of enhanced natural gas recovery by injecting anthropogenic CO2 (Oldenburg et al. 2001).SCHLUMBERGERSPE105041Reservoir PerformanceMechanismEffect of WettabilityA Quantitative Model for the Effect of Wettability on the Conductivity of Porous RocksBernard Montaron, SPE, SchlumbergerAbstract Reservoir rock wettability is an important parameter to consider for oil recovery optimization. The great majority of sandstone formations is known to be strongly water-wet. In contrast most carbonate reservoir rocks are believed to be mixed-wet or oil-wet to some degree with a non-uniform distribution of the wettability in the reservoir. Despite the importance of this parameter there is currently no proven quantitative logging technique that can provide a continuous wettability log. A detailed analysis of a new model for the conductivity of reservoir rock called the connectivity equation is provided in the paper. Similar to Archie's law this simple model has only two parameters: An exponent called the conductivity exponent and the water connectivity parameter Cw. Under some conditions Cw can be equal to zero and the equation becomes identical to Archie's law in its simplest form (n = m = ). However in the general case the model is fundamentally different from Archie's law because in the connectivity equation resistivity is only a function of the water volume fraction. Cw is shown to account for water connectivity effects in the pore network. These effects are encoded in the expression of Cw with three terms linked respectively to 1-the super-connectivity of micro pores in micritic grains for carbonate rocks or the super-connectivity created by shale in shaly sandstones 2- wettability effects in meso/macro pores and 3-the low connectivity of vuggy porosity. This model is compared with published data and is shown to correctly account for most situations including 'non-Archie' rocks such as low resistivity pay in carbonates strongly oil-wet rocks and the dual water model for shaly sands. A good correlation between Cw - obtained from a combination of wireline logs - and wettability measured on cores is found on data from a Middle East carbonate reservoir.SCHLUMBERGERSPE116063Reservoir PerformanceMechanismFines MigrationFines Migration Evaluation in a Mature Field in LibyaKaibin Qiu, Schlumberger; Yousef Gherryo and Mohamed Shatwan, AGOCO (Libya); and John Fuller, SPE, and Wesley Martin, SPE, SchlumbergerAbstract An experimental study was conducted on the mature Messla field to investigate the mechanism of fines migration and its contribution in formation damage. In the study an advanced laboratory test programme was designed after investigation of production history well performance in-situ stress state and depletion history. The programme included critical velocity tests and pore volume Compressibility (PVC) fines migration tests. The critical velocity tests investigated the relationship between flow rate and decrease of permeability by flowing the core plug at different flow rate and concurrently measuring corresponding permeability. Additionally alternating flow of kerosene and formation water was conducted in the tests to investigate the effect of water breakthrough on fines migration. The PVC fines migration tests were carried out by applying triaxial loading to the samples that followed the stress path of reservoir depletion to identify any critical depletion level that may damage the formation during reservoir production. Concurrently horizontal flow measurements were made with the PVC tests to simulate production. In addition produced fines were evaluated by using standard light microscope and Scanning Electron Microscopy (SEM). The composition of any fines collected is further identified through X-Ray Diffraction (XRD) analysis. Through these tests the tendency and severity of fines migration in this field were investigated and the impact of reservoir depletion on permeability was revealed. Based on the knowledge the sandface completions were optimized to improve their performance. Introduction The giant Messla field is located in the southeast portion of Sirte Basin in Libya approximately 500 km southeast from Benghazi.1 The field operated by AGOCO has been producing since the year 1971. Currently production decline has been observed from many wells in this field. It was recognized that to address production decline in the field a comprehensive investigation had to be conducted to delineate the major contributing factors. Understanding the mechanism of fines migration and its contribution to formation damage is an essential aspect of the study. Once understood remedies such as acidization or fines stabilization can be applied to effectively address formation damage and improve production. Furthermore the knowledge will also provide pertinent guidance on the design of sandface completions to address the sanding issues in the field.1 Literature review indicated that formation fines are ubiquitous in oil- and gas-bearing sandstones 2 3 4 5 especially in unconsolidated materials.6 Fines migration generally refers to small solid unattached particles of sand and/or clay which have become dislodged entrained in the flowing fluids and transported through the porous formation towards the well. During migration fines can bridge pore throats and restrict fluid movement.7 This process can severely damage the formation as well as sandface completions 8 9 10 11 12 thereby causing devastating effect on the productivity of wells or reservoirs. In the last 30 years different attempts have been made to address fines migration and related formation damage.3 6 12 13 14 15 16 17 18 19 To address the problems of production decline in the Messla field an investigation of fines migration and its involvement in formation damage was regarded as essential. A key finding of previous investigations in the industry is that there is a critical velocity or flow rate below which entrainment of fines does not occur and above which the rate of entrainment increases linearly with flow rate.5 7 8 11 13 17 20 21 Therefore it is often observed from a flowing test that at initial low flow rate the permeability of the core sample remains constant but once the flow rate increases to a critical level there is sharp decrease in permeability. In this study critical velocity tests were conducted to determine if fines migration is an issue in the production of Messla reservoir sandstone and if so at what production rates fines migration would become an issue.OnePetroOnePetroSHELLSPE103054Reservoir PerformanceMechanismFluid Mixing IssuesFlow Reversal and MixingRaman K. Jha, Abraham K. John, Steven L. Bryant, and Larry W. Lake, University of Texas at AustinSummary Flow-reversal studies provide insights into mixing mechanisms in flow through porous media. In these studies the direction of flow is reversed after the solute slug has penetrated into the medium (but not exited) to a predetermined distance. We simulated the effect of flow reversal on mixing in 2D porous media using two different approaches. In the first approach we perform direct numerical simulation of a solute-slug transport (by solving Navier-Stokes and convection/diffusion equations) in a surrogate pore space. This approach allows a direct visualization of mixing in simple flow geometries. The effect of flow reversal on mixing is investigated for several diffusion coefficients penetration depths and flow geometries. The second approach uses particle tracking to simulate the effect of flow reversal at larger length scales. This approach is free of numerical dispersion can be used in the absence of diffusion and has no limits on the size of the simulation. It is however limited to layered-media flow. The simulation studies presented in this paper explain the mechanism of mixing and the origin of the irreversibility of dispersion in flow through porous media. We also explain several experimental observations on flow-reversal tests found in the literature. Mixing in porous media takes place because of interaction between convective spreading and molecular diffusion. The converging/diverging paths and flow around impervious sand grains cause the solute front to stretch and split. In this process the area of contact between the solute slug and the resident fluid increases by an order of magnitude and diffusion becomes an effective mixing mechanism. This local mixing caused by diffusion is irreversible. For purely convective transport solute particles retrace their path back to the inlet upon flow reversal. Convective spreading gets canceled and echo dispersion is 0. Diffusion even though small in magnitude is responsible for local mixing and making dispersion in porous media irreversible. Thus it is important to include the effect of diffusion when analyzing miscible displacements in porous media.OnePetroBPSPE107137Reservoir PerformanceMechanismHeretrogeneous FlowImpact of Heterogeneity on Flow in Fluvial-Deltaic Reservoirs: Implications for the Giant ACG Field, South Caspian BasinKevin Choi, Matthew Jackson, and Gary Hampson, Imperial College London, and Alistair Jones, and Tony Reynolds, BPAbstract The ACG Oilfield caps an elongate anticline with three culminations - Azeri Chirag and Gunashli - and is located in the offshore Azerbaijan sector of the south Caspian Basin. This study focuses on Azeri in the south-east of the structure which has over 8 billion barrels of oil in place. The major reservoir interval the Pliocene Pereriv Suite is characterized by laterally continuous layers of variable net-to-gross (NTG) deposited in a fluvialdeltaic environment. Azeri is being developed by down-dip water injection with up-dip gas injection on the more steeply dipping central north flank. At the planned offtake rates both recovery mechanisms are expected to be stable. However these predictions are based on reservoir models which do not explicitly capture the full range of geologic heterogeneity present in the Pereriv Suite reservoirs. We report the first detailed assessment of the impact of large- and intermediate-scale heterogeneities on flow. Experimental design techniques have been used to rank the impact of different heterogeneities. A key finding is that communication between adjacent high and low NTG reservoir layers significantly improves recovery providing pressure support and a route for oil production from sandbodies within the low NTG layers which would otherwise be isolated. Heterogeneity within high NTG layers has only a small impact on recovery but heterogeneity within low NTG layers is much more significant. In most cases the same significant heterogeneities impact both water and gas displacements because both displacements are stable at the planned production rates. The results are applicable to Azeri and to similar reservoirs in the Caspian Basin. They also represent the first comparison of water-oil and gas-oil displacements in fluvial-deltaic reservoirs using 3D geologic/simulation models derived from outcrop and subsurface data. Introduction The giant Azeri-Chirag-Gunashli (ACG) Field occurs in a large elongate anticlinal structure located in the offshore Azerbaijan sector of the south Caspian Basin (Fig. 1A). The structure has steeply dipping limbs and contains three culminations (Azeri Chirag and Gunashli). This paper focuses on the Azeri accumulation in the south-east of the ACG structure which contains an estimated 8 billion barrels of oil in place. The ACG field development project is one of the largest current energy projects (US$20 billion aggregate) in the world. The Azerbaijan International Operating Company operated by BP has been awarded a 30 year production license for ACG which expires in 2025 and plans to bring total production in ACG to 1 million bbls oil/day by 2008. The oil fields of the South Caspian Basin (Fig. 1A) have reservoirs in the thick (up to 7000 m) latest Miocene to early Pliocene strata of the Productive Series (Fig. 2A). These strata record multiple high-frequency cycles of deltaic shoreline advance and retreat in response to fluctuating lake levels in the isolated South Caspian Basin1-4 (Fig. 1B). The resulting Productive Series stratigraphy is strongly layered (Fig. 2A) and sandstone-bearing intervals are bounded by laterally extensive mudstones1-4. Productive Series sandstones in the northern part of the South Caspian Basin (including the ACG Field) are quartz-rich well rounded and well sorted indicating deposition by the paleo-Volga River and Delta5 (Fig. 1B).SCHLUMBERGERSPE102715Reservoir PerformanceMechanismNon-Dacy FlowApplicability of the Forchheimer Equation for Non-Darcy Flow in Porous MediaH. Huang, SPE, and J. Ayoub, SPE, SchlumbergerAbstract The subject of non-Darcy flow in hydraulically fractured wells has generated intense debates recently. One aspect of the discussion concerns the inertia resistance factor or the so-called beta factor in the Forchheimer equation and whether the beta factor for a proppant pack should be constant over the range of flow rates of practical interests. The problem was highlighted in a recent discussion by Batenburg and Milton-Tayler1 and the reply by Barree and Conway2 regarding paper SPE 893253 in the JPT in August 2005. To properly assess all the arguments and to get a better understanding of the state-of-the-art on non-Darcy flow in porous media in general literature concerning the theoretical basis of the Forchheimer equation and experimental work on the identification of flow regimes is reviewed. These areas of work provide insights into the applicability of the Forchheimer equation to conventional oilfield flow tests for proppant packs. Models for flow beyond the Forchheimer regime are also suggested. Introduction The effect of non-Darcy flow as one of the most critical factors in reducing the productivity of hydraulically fractured high rate wells has been documented extensively with examples of field cases3-7. The inertia resistance factor or the so-called beta factor b a parameter in the Forchheimer equation for quantifying the non-Darcy flow effect is now routinely measured for proppant packs. Nevertheless how to derive the beta factor b from experimental data is still controversy. In a recent issue of the JPT in August 2005 there was a discussion by Batenburg and Milton-Tayler1 and the reply by Barree and Conway2 regarding paper SPE 893253 on whether the beta factor for a proppant pack should be constant over the range of flow rates of practical interests. The so-called non-Darcy flow in porous media occurs if the flow velocity becomes large enough so that Darcys law8 for the pressure gradient and the flow velocity i.e. (1) is no longer valid. In Eq. 1 permeability k is an intrinsic property of porous media. To describe the nonlinear flow situation a quadratic term was included by Dupuit9 and Forchheimer10 to generalize the flow equation i.e. (2) Eq. 2 is commonly known as the Forchheimer equation. In the discussion of Batenburg and Milton-Tayler1 and Barree and Conway 2 it was presumed that non-Darcy flow in their experiments can be described by the Forchheimer equation. According to the convention of the oil and gas industry the beta factor is generally deduced experimentally from the slope of the plot of the inverse of the apparent permeability 1/kapp vs. a dimensional pseudo Reynolds number V/ (also called the Forchheimer graph). The apparent permeability kapp is defined as (3) after rewriting the Forchheimer equation. Based on the linear correlations obtained between 1/kapp and V/ (see Fig. 1) Batenburg and Milton-Tayler1 concluded that the beta factor is constant for the range of flow rates of practical interests. It was recognized that the correlation however does not reduce to the inverse of Darcy permeability 1/k when extrapolated to zero velocity. Barree and Conway 2 on the other hand obtained a nonlinear concave down curve shape for the variation of 1/kapp vs. V/ (see Fig. 2) and concluded therefore that the beta factor is not constant over the range of investigation. It was argued that the fact that a linear correlation does not reduce to 1/k at zero velocity indicates that the correlation is insufficient.CHEVRONSPE96448Reservoir PerformanceMechanismRel. Perm. HysteresisA New Model of Trapping and Relative Permeability Hysteresis for All Wettability CharacteristicsElizabeth J. Spiteri, SPE, Chevron Energy Technology Company; Ruben Juanes, SPE, Massachusetts Institute of Technology; Martin J. Blunt, SPE, Imperial College London; and Franklin M. Orr, Jr., SPE, Stanford UniversitySummary The complex physics of multiphase flow in porous media are usually modeled at the field scale using Darcy-type formulations. The key descriptors of such models are the relative permeabilities to each of the flowing phases. It is well known that whenever the fluid saturations undergo a cyclic process relative permeabilities display hysteresis effects. In this paper we investigate hysteresis in the relative permeability of the hydrocarbon phase in a two-phase system. We propose a new model of trapping and waterflood relative permeability which is applicable for the entire range of rock wettability conditions. The proposed formulation overcomes some of the limitations of existing trapping and relative permeability models. The new model is validated by means of pore-network simulation of primary drainage and waterflooding. We study the dependence of trapped (residual) hydrocarbon saturation and waterflood relative permeability on several fluid/rock properties most notably the wettability and the initial water saturation. The new model is able to capture two key features of the observed behavior: (1) non-monotonicity of the initial-residual curves which implies that waterflood relative permeabilities cross; and (2) convexity of the waterflood relative permeability curves for oil-wet media caused by layer flow of oil. Introduction Hysteresis refers to irreversibility or path dependence. In multiphase flow it manifests itself through the dependence of relative permeabilities and capillary pressures on the saturation path and saturation history. From the point of view of pore-scale processes hysteresis has at least two sources: contact angle hysteresis and trapping of the nonwetting phase. The first step in characterizing relative permeability hysteresis is the ability to capture the amount of oil that is trapped during any displacement sequence. Indeed a trapping model is the crux of any hysteresis model: it determines the endpoint saturation of the hydrocarbon relative permeability curve during waterflooding. Extensive experimental and theoretical work has focused on the mechanisms that control trapping during multiphase flow in porous media (Geffen et al. 1951; Lenormand et al. 1983; Chatzis et al. 1983). Of particular interest to us is the influence of wettability on the residual hydrocarbon saturation. Early experiments in uniformly wetted systems suggested that waterflood efficiency decreases with increasing oil-wet characteristics (Donaldson et al. 1969; Owens and Archer 1971). These experiments were performed on cores whose wettability was altered artificially and the results need to be interpreted carefully for two reasons: (1) reservoirs do not have uniform wettability and the fraction of oil-wet pores is a function of the topology of the porous medium and initial water saturation (Kovscek et al. 1993); and (2) the coreflood experiments were not performed for a long enough time and not enough pore volumes were injected to drain the remaining oil layers to achieve ultimate residual oil saturation. In other coreflood experiments in which many pore volumes were injected the observed trapped/residual saturation did not follow a monotonic trend as a function of wettability and was actually lowest for intermediate-wet to oil-wet rocks (Kennedy et al. 1955; Moore and Slobod 1956; Amott 1959). Jadhunandan and Morrow (1995) performed a comprehensive experimental study of the effects of wettability on waterflood recovery showing that maximum oil recovery was achieved at intermediate-wet conditions. An empirical trapping model typically relates the trapped (residual) hydrocarbon saturation to the maximum hydrocarbon saturation; that is the hydrocarbon saturation at flow reversal. In the context of waterflooding a trapping model defines the ultimate residual oil saturation as a function of the initial water saturation. The most widely used trapping model is that of Land (1968). It is a single-parameter model and constitutes the basis for a number of relative permeability hysteresis models. Other trapping models are those of Jerauld (1997a) and Carlson (1981). These models are suitable for their specific applications but as we show in this paper they have limited applicability to intermediate-wet and oil-wet media. Land (1968) pioneered the definition of a flowing saturation " and proposed to estimate the imbibition relative permeability at a given actual saturation as the drainage relative permeability evaluated at a modeled flowing saturation. Lands imbibition model (1968) gives accurate predictions for water-wet media (Land 1971) but fails to capture essential trends when the porous medium is weakly or strongly wetting to oil. The two-phase hysteresis models that are typically used in reservoir simulators are those by Carlson (1981) and Killough (1976). A three-phase hysteresis model that accounts for essential physics during cyclic flooding was proposed by Larsen and Skauge (1998). These models have been evaluated in terms of their ability to reproduce experimental data (Element et al. 2003; Spiteri and Juanes 2006) and their impact in reservoir simulation of water-alternating-gas injection (Spiteri and Juanes 2006; Kossack 2000). Other models are those by Lenhard and Parker (1987) Jerauld (1997a) and Blunt (2000). More recently hysteresis models have been proposed specifically for porous media of mixed wettability (Lenhard and Oostrom 1998; Moulu et al. 1999; Egermann et al. 2000). All of the hysteresis models described require a bounding drainage curve and either a waterflood curve as input or a calculated waterflood curve using Lands model. The task of experimentally determining the bounding waterflood curves from core samples is arduous and the development of an empirical model that is applicable to non-water-wet media is desirable. In this paper we introduce a relative permeability hysteresis model that does not require a bounding waterflood curve and whose parameters may be correlated to rock properties such as wettability and pore structure. Because it is difficult to probe the full range of relative permeability hysteresis for different wettabilities experimentally we use a numerical tool--pore-scale modeling--to predict the trends in residual saturation and relative permeability. As we discuss later pore-scale modeling is currently able to predict recoveries and relative permeabilities for media of different wettability reliably (Dixit et al. 1999; ren and Bakke 2003; Jackson et al. 2003; Valvatne and Blunt 2004; Al-Futaisi and Patzek 2003 2004). We will use these predictions as a starting point to explore the behavior beyond the range probed experimentally. In summary this paper presents a new model of trapping and waterflood relative permeability which is able to capture the behavior predicted by pore-network simulations for the entire range of wettability conditions."Imperial CollegeSPE96448Reservoir PerformanceMechanismRel. Perm. HysteresisA New Model of Trapping and Relative Permeability Hysteresis for All Wettability CharacteristicsElizabeth J. Spiteri, SPE, Chevron Energy Technology Company; Ruben Juanes, SPE, Massachusetts Institute of Technology; Martin J. Blunt, SPE, Imperial College London; and Franklin M. Orr, Jr., SPE, Stanford UniversitySummary The complex physics of multiphase flow in porous media are usually modeled at the field scale using Darcy-type formulations. The key descriptors of such models are the relative permeabilities to each of the flowing phases. It is well known that whenever the fluid saturations undergo a cyclic process relative permeabilities display hysteresis effects. In this paper we investigate hysteresis in the relative permeability of the hydrocarbon phase in a two-phase system. We propose a new model of trapping and waterflood relative permeability which is applicable for the entire range of rock wettability conditions. The proposed formulation overcomes some of the limitations of existing trapping and relative permeability models. The new model is validated by means of pore-network simulation of primary drainage and waterflooding. We study the dependence of trapped (residual) hydrocarbon saturation and waterflood relative permeability on several fluid/rock properties most notably the wettability and the initial water saturation. The new model is able to capture two key features of the observed behavior: (1) non-monotonicity of the initial-residual curves which implies that waterflood relative permeabilities cross; and (2) convexity of the waterflood relative permeability curves for oil-wet media caused by layer flow of oil. Introduction Hysteresis refers to irreversibility or path dependence. In multiphase flow it manifests itself through the dependence of relative permeabilities and capillary pressures on the saturation path and saturation history. From the point of view of pore-scale processes hysteresis has at least two sources: contact angle hysteresis and trapping of the nonwetting phase. The first step in characterizing relative permeability hysteresis is the ability to capture the amount of oil that is trapped during any displacement sequence. Indeed a trapping model is the crux of any hysteresis model: it determines the endpoint saturation of the hydrocarbon relative permeability curve during waterflooding. Extensive experimental and theoretical work has focused on the mechanisms that control trapping during multiphase flow in porous media (Geffen et al. 1951; Lenormand et al. 1983; Chatzis et al. 1983). Of particular interest to us is the influence of wettability on the residual hydrocarbon saturation. Early experiments in uniformly wetted systems suggested that waterflood efficiency decreases with increasing oil-wet characteristics (Donaldson et al. 1969; Owens and Archer 1971). These experiments were performed on cores whose wettability was altered artificially and the results need to be interpreted carefully for two reasons: (1) reservoirs do not have uniform wettability and the fraction of oil-wet pores is a function of the topology of the porous medium and initial water saturation (Kovscek et al. 1993); and (2) the coreflood experiments were not performed for a long enough time and not enough pore volumes were injected to drain the remaining oil layers to achieve ultimate residual oil saturation. In other coreflood experiments in which many pore volumes were injected the observed trapped/residual saturation did not follow a monotonic trend as a function of wettability and was actually lowest for intermediate-wet to oil-wet rocks (Kennedy et al. 1955; Moore and Slobod 1956; Amott 1959). Jadhunandan and Morrow (1995) performed a comprehensive experimental study of the effects of wettability on waterflood recovery showing that maximum oil recovery was achieved at intermediate-wet conditions. An empirical trapping model typically relates the trapped (residual) hydrocarbon saturation to the maximum hydrocarbon saturation; that is the hydrocarbon saturation at flow reversal. In the context of waterflooding a trapping model defines the ultimate residual oil saturation as a function of the initial water saturation. The most widely used trapping model is that of Land (1968). It is a single-parameter model and constitutes the basis for a number of relative permeability hysteresis models. Other trapping models are those of Jerauld (1997a) and Carlson (1981). These models are suitable for their specific applications but as we show in this paper they have limited applicability to intermediate-wet and oil-wet media. Land (1968) pioneered the definition of a flowing saturation " and proposed to estimate the imbibition relative permeability at a given actual saturation as the drainage relative permeability evaluated at a modeled flowing saturation. Lands imbibition model (1968) gives accurate predictions for water-wet media (Land 1971) but fails to capture essential trends when the porous medium is weakly or strongly wetting to oil. The two-phase hysteresis models that are typically used in reservoir simulators are those by Carlson (1981) and Killough (1976). A three-phase hysteresis model that accounts for essential physics during cyclic flooding was proposed by Larsen and Skauge (1998). These models have been evaluated in terms of their ability to reproduce experimental data (Element et al. 2003; Spiteri and Juanes 2006) and their impact in reservoir simulation of water-alternating-gas injection (Spiteri and Juanes 2006; Kossack 2000). Other models are those by Lenhard and Parker (1987) Jerauld (1997a) and Blunt (2000). More recently hysteresis models have been proposed specifically for porous media of mixed wettability (Lenhard and Oostrom 1998; Moulu et al. 1999; Egermann et al. 2000). All of the hysteresis models described require a bounding drainage curve and either a waterflood curve as input or a calculated waterflood curve using Lands model. The task of experimentally determining the bounding waterflood curves from core samples is arduous and the development of an empirical model that is applicable to non-water-wet media is desirable. In this paper we introduce a relative permeability hysteresis model that does not require a bounding waterflood curve and whose parameters may be correlated to rock properties such as wettability and pore structure. Because it is difficult to probe the full range of relative permeability hysteresis for different wettabilities experimentally we use a numerical tool--pore-scale modeling--to predict the trends in residual saturation and relative permeability. As we discuss later pore-scale modeling is currently able to predict recoveries and relative permeabilities for media of different wettability reliably (Dixit et al. 1999; ren and Bakke 2003; Jackson et al. 2003; Valvatne and Blunt 2004; Al-Futaisi and Patzek 2003 2004). We will use these predictions as a starting point to explore the behavior beyond the range probed experimentally. In summary this paper presents a new model of trapping and waterflood relative permeability which is able to capture the behavior predicted by pore-network simulations for the entire range of wettability conditions."SHELLSPE115274Reservoir PerformanceMechanismRock CompactionImpact of Pore Volume Compressibility on Recovery from Depletion Drive & Miscible Gas Injection in South OmanByron Haynes, Jr., Ahmed Abdelmawla and Simon Stromberg, Petroleum Development OmanAbstract Rock Pore Volume Compressibility (PVC) data can be misinterpreted during the early life of reservoir development due to the fact that there are minimal amounts of this data acquired during early reservoir life. This data is typically obtained from uniaxial or hydrostatic tests using conventional core acquired during the appraisal phase of the reservoir. This article presents a case study from a cluster of reservoirs in Southern Oman that highlights the importance of using PVC to determine reserves associated with both the primary depletion and miscible gas injection. The cluster is being developed in a phased approach. The key objective of each phase is to gather data from the different reservoirs to assess if a miscible gas injection project would be feasible. Permanent downhole pressure gauges have been utilized to monitor reservoir performance from the depletion phase and to aid in the forecasting of oil recovery for the miscible gas injection projects. The reservoir pressure in one of the reservoirs producing in the depletion phase has declined faster than expected and can be attributable to either lower than expected oil in place volume or a lower the expected PVC. Obviously having lower oil volumes in place would greatly impact the economics of a miscible gasflood development. Therefore renewed focus on proper evaluation of the PVC from the latest emerging core data from appraisal wells in a this reservoir has indicated that although the originally assumed PVC was within the uncertainty range it was at the high range of the data and some of the measured data was skewing the average. A new look at the material balance and simulation results verified that PVC and not a reduction in OOIP was the root cause of the difference in performance estimates and the observed reservoir performance. By using a new lower average PVC the observed reservoir pressure is found to be consistent with new material balance and reservoir simulation results. This approach has clearly provided vital information to underpin the recoverable reserves associated with the miscible gas injection. Introduction Rock Pore Volume Compressibility (PVC) data can be misinterpreted during the early life of reservoir development due to the fact that there are minimal amounts of this data acquired during early reservoir life. This data is typically obtained from uniaxial or hydrostatic tests using conventional core acquired during the appraisal phase of the reservoir. This paper presents a case study from a green field reservoir in South Oman for estimating recovery from primary depletion and miscible gas injection processes and highlights the importance of using the correct PVC in undersaturated oil reservoirs. The reservoir under consideration is part of of a cluster of fields located south of Oman Fig.1. The cluster consists of a group of fields discovered between 1996 and 2007. These reservoirs are deep and high pressure reservoirs with some over-pressured (lithostatically pressured). These reservoirs are carbonate stringers encased in salt with different cycles of deposition Fig. 2. The reservoir rock is Ara 2 Carbonate (A2C) which is mainly dolomite with some Limestone. In this reservoir dolomitization is linked to the productive intervals.SHELLSPE102186Reservoir PerformanceMechanismSteam InjectionThe Physics of Steam Injection in Fractured Carbonate Reservoirs: Engineering Development Options That Minimize RiskG.T. Shahin Jr, SPE, Shell E&P Technology; R. Moosa, SPE, PDO; B. Kharusi, SPE, and G. Chilek, Shell E&P TechnologyAbstract Naturally fractured carbonate reservoirs hold well over 100 billion barrels of heavy oil worldwide. Thermally Assisted Gas Oil Gravity Drainage (TAGOGD) is a new and novel thermal EOR technique which has applicability in selected reservoirs. In conventional isothermal GOGD vertical fractures cause the gas-oil contact in the fracture system to advance ahead of the gas-oil contact within the matrix blocks causing the oil in these blocks to become mobile. The addition of heat in the fractures generates additional hydrocarbon gas cap lowers the viscosity of the oil and accelerates conventional GOGD as seen in the 220 cp heavy-oil Qarn Alam field in Oman. Pilot results in the Qarn Alam field support the commerciality of this process and a first-of-its-kind steam injection project is being implemented. The economic success of the Qarn Alam project depends on the ability to credibly predict steam requirements and oil production. Two key oil production mechanisms are heat transport through the fractures and into the matrix and subsequent gas cap generation due to thermal volatilization of the oil. The process mechanisms involved in TAGOGD were validated through laboratory experiments while the field forecast model results were validated by history matching pilot performance data. A fully integrated workflow of fracture characterization integrated reservoir physics and static and dynamic modeling has enabled uncertainties and risks involved in developing the Qarn Alam field to be managed in a scenario based design approach. Introduction The Qarn Alam field is a highly fractured carbonate field that lies atop a salt diapir in Northern Oman. The 6 km long and 3 km wide field forms a relatively high-relief anticline with a N-NE by SSW orientation. The reservoir is relatively compact dome-shaped structure with a maximum oil column of 165 m. The main oil bearing reservoirs the Shuaiba and Kharaib formations are separated by a very low permeability oil bearing zone called the Hawar. The crest of the Shuaiba is located at 212 mss and the original oil water contact is ~375 mss. Fracturing occurs throughout all zones and is believed to be contiguous and in hydraulic communication with a very active aquifer. The initial oil saturation is about 95% and initial water saturation is connate water. The matrix porosity is high (~30%) while the matrix permeability ranges between 5 md-20 md. Under primary production the reservoir produces on average about 100 m3/day of 16o API heavy oil at a GOR of 10 m3/m3.SHELLSPE113464Reservoir PerformanceMechanismSteam InjectionExperimental Investigation of Steam Injection in Light Oil Fractured CarbonatesMarco Verlaan, Shell International Exploration and Production, Rijswijk, The Netherlands; Paul Boerrigter, Shell International Exploration and Production, Rijswijk, The Netherlands, Shell Technology Oman, Muscat, Sultanate of Oman;. Sjaam Oedai, Shell International Exploration and Production, Rijswijk, The Netherlands; and Johan van Dorp, Shell Technology Oman, Muscat, Sultanate of OmanAbstract Conventional displacement methods such as water flooding do not work effectively in densely fractured reservoirs. In such reservoirs one has to rely on recovery mechanisms like capillary imbibition or gravity to recover oil from the reservoir rock matrix. In oil-wet or mixed-wet fractured carbonates only gravity drainage remains a feasible process. However low permeabilities result in low gravity drainage production rates with high remaining oil saturation. EOR methods have the potential to improve GOGD drainage rate and ultimate recovery. Especially for shallow fractured reservoirs it may be attractive to inject steam to improve oil rate and recovery. Heating of the matrix will result in oil expansion reduction of viscosity solution gas drive and steam stripping of intermediate hydrocarbon components. Solution gas drive and steam stripping effects potentially become more important than the viscosity reduction. We experimentally investigated the physical mechanisms involved. We present the results of a laboratory study in which reservoir core with light crude oil at reservoir conditions is heated to steam temperature. From these experiments and separate PVT measurements the effects of thermal expansion of oil gas liberation and initial water saturation are investigated. The experiments are interpreted numerically by detailed modelling of the observed production. The results show that connate water has a big impact on the gas drive and distillation process and as a consequence enhances the oil recovery. Introduction The connected fracture network in densely fractured reservoirs has a strong impact on reservoir displacement mechanisms. Conventional displacement methods such as water flooding do not work effectively: due to the high fracture permeability it is not possible to establish significant pressure differentials across oil bearing matrix blocks to drive oil from matrix rock into the fracture system. In densely fractured reservoirs one relies on mechanisms like capillary imbibition or gravity to recover oil from the matrix reservoir rock. Fractured carbonate reservoirs are commonly oil wet or mixed wet and the main production mechanism is gravity. Once a gas cap is established in the fracture system the oil will drain down the matrix rock driven by gravity and into the fracture system at flow barriers. In the fracture system the oil forms a (thin) rim that can be produced. Production rates achieved with this GOGD (Gas Oil Gravity Drainage) process are often low due to low matrix rock permeability capillary hold-up and re-imbibition effects. Capillary hold-up also reduces ultimate recovery. Both miscible gas injection and steam injection are feasible EOR processes to accelerate the production and increase recovery. Steam injection in heavy oil reservoirs is common practice and recently receives more attention in naturally fractured reservoirs1-6. Steam injection in light oil reservoirs is not common although there are some examples of steam flooding non-fractured or sparsely fractured reservoirs7. Thermally assisted gas-oil gravity drainage (TA-GOGD) in light oil has not been done before. Burger8 already suggested that the increase in temperature in light oil naturally fractured reservoirs would lead to oil expulsion of significant quantities of oil from the matrix blocks into the fracture. The recovery mechanisms that play a role are very similar to those of a light oil steam flood9: Viscosity reduction Distillation Gas driveCHEVRONSPE91393Reservoir PerformanceMechanismWater VaporizationModeling of Experiments on Water Vaporization for Gas Injection Using Traveling WavesElizabeth Zuluaga* and Larry W. Lake, University of Texas at Austin, SPE * Now with Chevron Energy Technology CompanySummary Dry gas injected into wells will vaporize water from near the wellbore. The vaporization starts from the well and proceeds outward. Gas flowing to producers is in equilibrium with the reservoir brine but water will be vaporized because the pressure drop that occurs toward the wellbore increases the ability of the gas to contain water. Thus there are different mechanisms for injection and production. For both gas injection and gas production vaporization concentrates solids in the brine that will precipitate into the formation when sufficiently concentrated. This paper reports on a combined experimental and theoretical analysis on the vaporization portion of this problem for dry gas injection. Experiments have been performed previously to determine the rate of water vaporization from Berea core samples at uniform initial water saturation (Zuluaga and Monsalve 2003). These experiments were performed by injecting dry methane into core samples that contained immobile water to represent water vaporization in a gas injector. Effluent water concentration curves showed two vaporization periods: a constant rate period and a falling rate period. The existence of a constant rate period means that the mass transfer within the core is occurring at conditions of local equilibrium. We interpret the falling rate period as the result of a moving capillary transition zone in which the amount of water vaporized decreases slowly because of capillary pressure effects. The falling rate period is the consequence of capillary imbibition of a wetting phase at very small saturation. We interpret the vaporization results with two traveling wave solutions. The first which can be solved analytically assumes that the capillary diffusion coefficient D and the volume fraction of water in the gaseous phase Cwg are constant. For this case the results of the traveling wave solution are matched to the results of laboratory experiments by adjusting D. The second traveling-wave solution must be solved through numerical integration. In this case the relative permeability scaling exponent is adjusted to match the laboratory experiments. The fitting provides insights into the nature of wetting phase flow at small saturation. Lastly the experimental and mathematical procedure discussed in this paper is certainly a new method to obtain relative permeability exponents for the wetting phase at very low values of wetting-phase saturation (down to theoretically zero values). Introduction Dodson and Standing (1944) performed the first experimental study to determine the amount of water vaporized at different pressures and temperatures using PVT cells. They found that the rate of water vaporization increases with temperature and decreases with pressure and solids content in the water. Bette and Heinemann (1989) confirmed vaporization in cores taken from gas injectors in the Arun field. The water content in these cores was very small; in some cases the cores were completely dry. Kamath and Laroche (2000) and Mahadevan and Sharma (2005) performed experiments in permeable media that were initially fully saturated with brine. When gas was used as a displacing fluid there were two flow regimes: a displacement regimen followed by a vaporization regimen. Using gas as both a displacing agent and a drying agent makes the study of the vaporization alone difficult. Zuluaga and Monsalve (2003) performed vaporization experiments in permeable media at outlet pressures ranging from 1 000 to 2 000 psig and temperatures from 194 to 212F. The experiments were not displacements the initial water saturation being set as a nonflowing saturation by a porous plate method. Fig. 1 shows the rate of water production for an experiment performed at 1 500 psig outlet pressure and 194F. The experiments were perfomed by measuring the accumulated mass of water as it exited the medium and as it was sorbed on a silica substrate. The rate shown in Fig. 1 was obtained by differentiating the cumulative data with respect to time. Two vaporization periods occur: a constant rate period and a falling rate period. These two periods of water vaporization have been extensively reported for drying of solids (ceramic wood) in the chemical engineering literature (Allerton 1949; Perry and Green 1984; Mujumdar 1987). Our goal is to understand and quantify this behavior. There has been little modeling of water vaporization for flow through permeable media. Most approaches have been based on modifications of existing compositional simulators by incorporating water as a component in the equation of state (Bette and Heinemman 1989; Kurihara et al. 2000). The effect of salinity has been included either with salinity-dependent solubility tables (Morin and Montel 1995) or by adding salt as a component in an equation of state (Lee and Lin 1999). Some have modified material balance equations to account for water vaporization (Humphreys 1991). This study formulates and obtains solutions to the conservational laws describing water vaporization. We study the vaporization for gas injectors as a traveling wave in which capillary imbibition occurs. The solution obtained allows predictions of remaining water saturation with distance and time during both the constant and the falling rate periods (Zuluaga 2005).Heriot Watt UniversitySPE128607Reservoir PerformanceMechanism - DiagenesisNorth Morecombe FieldRecovery Behaviour of a Partly Illitized Sandstone Gas ReservoirAnthony O. Uwaga, SPE, Centrica EnergyAbstract Diagenesis is defined as any chemical physical or biological change undergone by a sediment (rock) after its initial deposition and during and after its lithification exclusive of surface alteration (weathering) and metamorphism. The diagenetic changes that occur in the rock result in the alteration of some of the original petrophysical properties of the rock. Porosity and permeability amongst others have been established to be altered by diagenesis. It is common knowledge in the industry that the amount of hydrocarbon recovered from a reservoir is dependent amongst other factors on the hydrocarbon initially-in-place in the reservoir and the intra reservoir rock pore space conn