A simple and efficient approach has been developed for improving the predictions of gas and liquid phase viscosities of reservoir fluids. The proposed method was based on the Lohrenz-Bray-Clark (LBC) correlation and applied to the Peng-Robinson equation of state (EOS) as all example although it can be applicable to any EOS. It can significantly improve the predictions of gas and liquid phase viscosities of hydrocarbon mixtures, particularly of high viscosity fluids. The approach is quite suitable for equation of state (EOS) based reservoir simulators and can further improve the prediction of reservoir fluid viscosity with appropriate tuning of the EOS.
Accurate predictions of gas and liquid phase viscosities of reservoir fluids are required in reservoir simulators, particularly in equation of state (EOS) based reservoir simulators. Many researchers have focused their attention on improving the prediction of gas and liquid viscosities. However, most of the methods from mathematically rigorous to completely empirical forms are only applicable to either gas phase or liquid phase within a limited range of composition, temperature and pressure. In reservoir simulations related to oil and gas production, viscosity prediction methods are required to be applicable to a wide range of hydrocarbon mixtures at various conditions. The Lohrenz-Bray-Clark (LBC) correlation is probably the most used one in reservoir simulation models. The correlation was based on the Jossi-Stiel-Thodos correlation and modified by Lohrenz et al. The correlation is related to a fourth-degree polynomial in the reduced density. The disadvantage of the correlation is that the predicted viscosity is very sensitive to the density which is normally determined by a cubic EOS and may be very inaccurate for high viscosity fluids. Alternatively Ely and Hanley presented an extended corresponding states model for predicting the viscosity of non-polar pure fluids and their mixtures. Pedersen and Fredenslund studied this method and proposed a new corresponding states method which is based on the principle of corresponding states with methane as the reference component. Later Aasberg-Petersen et al. further improved the model by introducing n-decane as the second reference component. Little and Kennedy used an analogy with the van der Waals EOS to correlate the viscosity of reservoir fluids. Lawal applied the Lawal-Lake-Silberberg EOS to correlate the viscosity as well.
In this study, a simple and efficient approach is proposed to improve the predictions of gas and liquid viscosities of reservoir fluids. The new method is based on the LBC correlation with the introduction of an exponential term and incorporating a cubic EOS. The method has been used to predict the viscosities of pure components, binary mixtures and reservoir fluids over a wide range of pressures and temperatures. The predicted results demonstrate that the new method can significantly improve the accuracy of viscosity predictions when compared with other published methods, particularly for high viscosity fluids. It is shown that the predictions can be further improved by appropriate tuning of the EOS.
As the Lohrenz-Bray-Clark (LBC) correlation is expressed as a function of the reduced density, the calculated viscosity is very sensitive to the density.
Akgun, F. (University of New South Wales) | Gurakin, G. (Colorado School of Mines) | Mitchell, B.J. (Colorado School of Mines) | Eustes, A. (Colorado School of Mines) | Rahman, S. (University of New South Wales)
Inadequate weight on bit leads to drilling at lower rate of penetration which reflect itself with expensive drilling intervals. Weight on bit is provided by slacking of some of the weights of the tubulars on bit. From the mechanical point of view this means putting bottom section of drill string into compression. The upper limit of the compressional stress that can be imposed on a drill string is bounded by the minimum stress which can lead to the failure of the tubulars. One type of the failure of drill string is called 'drill string buckling'. As the size of tubular decreases, their ability to transmit weight on bit without buckling decreases. Curvature and inclination of drilled hole increase or decrease the amount of compressional load that can be imposed on tubular without buckling. This load is known as Critical Buckling Load. This paper presents a finite element and an experimental approaches to predict the critical buckling load for dropping and building sections of holes.
Drilling at minimum cost necessitates optimum weight on bit. This weight is provided by slacking off some of the weights of drill string on bit. As the hook load decreases and slacked off length increases neutral point moves up in the drill string. At the same time, compressional stresses below the neutral point increase. There is a critical value of compressional stresses such that below which pipes are stable. In other word, pipes still have resistance against bending. However, if this value is exceeded then they will shown no resistance against bending. This phenomenon is known as buckling of tubulars and this critical value is known as Critical Buckling Load.
Buckling is not desired in drillstring because of several reasons. One of the reasons is that it may lead to premature failure of the drillstring through fatigue and erosion. It may lead to termination of drilling due to drill string lockup especially in horizontal wells. Lockup occurs when the compression at any location within the drill string is equal to or is greater than the drillstring's resistance to buckling at that location. Therefore, it becomes impossible to provide the necessary weight on bit. Without the weight on the bit, drilling ceases and drilling of the reach is terminated. Therefore, it is essential to determine the maximum load that can be imposed on drillstring.
Critical Buckling Load is not a unique number for a given diameter pipe. There are a number of borehole parameters affecting the magnitude of it. Such as, hole curvature, hole inclination, hole to pipe friction, etc. (Figure 1). Therefore, Critical Buckling Load for a given size pipe can not be determined independent without taking borehole data into consideration.
Compressive load at which pipes buckle can be predicted based on Eigenvalue analyses or based on large Deflection Analysis of Finite Elements Methods. Eigenvalue analysis has the short coming of estimating the upper bound of critical buckling load (bifurcation load). Whereas, the more critical lower bound can be predicted with Large Deflection analysis of Finite Elements Methods (Figure 2).
This study makes use of large deflection analysis of FEM to predict the critical buckling load in dropping holes. This paper also presents an experimental study to predict the critical buckling load in building holes.
FEM modelling of the Drill Pipe and Bore Hole
During a buckling simulation, the drill pipe is released and is allowed to slide down the wall of the borehole and settle into a stable position within the borehole. The pipe may or may not be buckled at the end of the simulation. If the pipe is buckled there will be a length of pipe in contact with the opposite side of the wall of the borehole (high side). The force created by the contact is called the contact force. It's direction is normal to the wall of the borehole.
Whether the pipe buckles or only bends, two forces acting on the drill pipe will be created.
Significant technological advances in methods and equipment have permitted increased drilling in deeper waters, often beyond continental shelves. Completion techniques have also advanced to allow efficient deepwater production. When designing a deepwater or subsea completion, traditional downhole challenges are complicated by subsea wellhead conditions that require advanced practices and equipment. This paper will acquaint the reader with characteristics unique to deepwater, subsea completions and present new completion accessories that maximize performance throughout the life of the well. Included will be a case study of a new use of electronics, dynamic seal assemblies and deepwater subsurface safety systems by an operator in deepwater Gulf of Mexico.
When considering deepwater exploitation, not only are the issues of wellhead changed, but also downhole equipment must be modified due to surface and ocean floor conditions. In the design and installation phase of the completion and subsequent life of the well, the presence of certain design parameters and the ease of installation must be considered as well as how any future stimulation, intervention or workover will be accomplished and/or accommodated. This paper will put forth thought processes that must go into a subsea completion design and present a deepwater completion typical of those being used in the Gulf of Mexico.
Tubular design must address some unique aspects of a subsea completion. In addition to wellhead placement on the ocean floor, many wells are highly deviated to horizontal, with obvious impact on tubular and production string design.
Stimulation. The tubular design must address any future well intervention or stimulation modes. The stimulation mode differs in a subsea completion from that of a surface completion. Temperature versus depth, from the surface, increases in a linear fashion in most surface or shallow water completions (Fig 1).
The subsea completion temperature increase is not linear. As fluids are pumped from the surface, they are cooled by surrounding waters until the wellhead depth is reached, at which time the temperature versus depth begins to increase in a linear fashion (Fig 2).
This paper describes the combination of integrated petroleum engineering studies with probabilistic decision making to assess the value of information of an appraisal well in a mature field.
The implementation of a cost effective pressure maintenance in the St Joseph Field offshore Malaysia has required consideration of several options, one of which is reverse dump flooding of the oil reservoir from underlying unconnected aquifers. A reverse dump flooding scheme would require drilling of a pilot well to collect additional data on the aquifers. Justification of the pilot (appraisal) well involved a series of studies based on limited data to establish that the dump flooding process had a sufficient probability of leading to a development with better economics than a gas injection scheme.
The aquifer assessment used seismic, biostratigraphic, pressure, regional data, and trend data from logs to define a distribution of connected aquifer size and quality. Well studies defined the ranges of aquifer productivity and oil leg injectivity and resulted in a flexible well completion that could be converted to a production well. Full field reservoir simulation estimated the aquifer and well performance ranges to derive a probability distribution of likely water dump volume and incremental oil reserves. Screening economics were performed and compared with gas injection. Monte Carlo simulation of the many combinations allowed definition of the probabilities as input for a decision tree analysis. Analytical well test simulation showed that uncertainties would remain in aquifer volumes after a pilot test, and needed to be incorporated into the decision tree. Ultimately the value of information of the pilot well was quantified to show an economic justification for pursuing the dump flooding option.
St. Joseph Field (Fig. 1.) has been on production since February 1982. At end 1995, the field had produced 105 MMstb oil out of the total ultimate recovery estimated at 230 MMstb. The recovery mechanism to date has been natural depletion under gravity drainage with string-by string control of gas-oil-ratio imposed. Current production potential is 28 Mb/d. Average reservoir pressure has fallen from 1060 psia to about 600 psia with an expanding secondary gas cap, and abandonment pressure under gas lifting is approximately 350 psia.
Of the 550 MMstb oil initially in place (STOIIP) in St Joseph Field, 83% is located in the main reservoir package in the Northwest Flank, which is a simple structure dipping at 20 degrees and sealed by a major strike-slip fault (Fig. 2). The oil reservoirs are Miocene age sands (Stage IVC) with intercalated shales deposited in outer shelf to deltaic/lagoonal environments. The reservoir package is sealed against a major transverse fault. Gross reservoir hydrocarbon thickness is 1450 ft true vertical with the crest of the structure at only 1280 ft ss. Sand porosities and permeabilities are good in the oil column, generally deteriorating down flank into the aquifer. In addition, major slump features have removed large reservoir sections in the aquifer. Direct aquifer influx to the main reservoir package is weak. 3D seismic data show strong continuous reflectors underneath the reservoir package, indicating a thick Stage IVA sequence of which the upper part has penetrated by eleven wells. Log and RFT measurements indicate that Stage IVA sands are water bearing and are overpressured by 60-90 psi. The Stage IVA and IVC deposits are separated by the Upper Intermediate Unconformity (U.I.U).
Pressure Maintenance Options
Three main options for secondary recovery have been considered for St Joseph:
George, S.C. (CSIRO Division of Petroleum Resources) | Lisk, M. (CSIRO Division of Petroleum Resources) | Eadington, P.J. (CSIRO Division of Petroleum Resources) | Quezada, R.A. (CSIRO Division of Petroleum Resources) | Krieger, F.W. (CSIRO Division of Petroleum Resources) | Greenwood, P.F. (CSIRO Division of Petroleum Resources) | Wilson, M.A. (University of Technology Sydney)
S.C. George, M. Lisk, P.J. Eadington, R.A. Quezada, F.W. Krieger, P.F. Greenwood, CSIRO Division of Petroleum Resources and Australian Petroleum Cooperative Research Centre, and M.A. Wilson, Department of Chemistry, University of Technology Sydney
This paper describes the use of oil-bearing fluid inclusions as time-specific markers of different oil migration events. Fluid inclusions are small samples of pore fluid trapped in framework minerals due to brittle deformation and fracturing during burial, or in diagenetic minerals during crystallisation. Recent advances in analytical techniques and instrumentation mean that it is now feasible to obtain detailed geochemical data on the trapped oils, which can be directly compared with either reservoired oils or with putative source rocks. Two techniques are currently being used, an off-line method which is suitable for comparing high molecular weight biomarker distributions and an on-line method which provides compositional data for the complete fluid which is trapped, including low molecular weight hydrocarbons and gases.
In this paper the results from two case studies involving the Jabiru and South Pepper oilfields are discussed. At Jabiru the oil trapped in fluid inclusions is genetically-related to, but is less mature than, the currently reservoired charge. This suggests continued expulsion of progressively more mature oil from the same or similar source rock facies. At South Pepper the fluid inclusion oil is both more mature and derived from a different, more calcareous source rock than the currently reservoired oil. The early oil is most likely derived from Triassic source rocks and was heavily biodegraded before re-charge of the South Pepper structure with Jurassic-sourced oil and gas.
Molecular composition of inclusion (MCI) studies such as these are powerful tools for elucidating the petroleum charge history to reservoirs. They provide molecular geochemical data on early oil charges which, when compared to presently reservoired oil, can be used to describe the changing nature of reservoir fluids through time. They are successfully being applied to other reservoirs on the North-west Shelf of Australia, either in dry holes or where there is currently gas and where fluid inclusion oil represents the only sample of oil charge.
Generated oil migrating to a reservoir rarely displays a uniform composition over time. Source rock horizons become more mature during burial, so will generate oil with progressively changing geochemistry. Deeper source rocks start generating oil, leading to variations in geochemical source parameters in the later oil charges. Earliest oil charge is likely to fill the largest pores and continued migration will fill progressively smaller pores and may mix with earlier charges. Reconstructing the oil charge history from the currently reservoired petroleum is complex, with considerable uncertainty as to the timing, source and phases of oil charge. One difficulty is the absence of end-member signatures due to the homogenisation process in the reservoir.
One approach is the use of oil-bearing fluid inclusions as time-specific markers of different oil migration events. Oil inclusions are small samples (usually <10 m in diameter) of pore fluid encapsulated in framework minerals such as quartz, feldspar and carbonate as they crystallise. Oil inclusions form during the crystallisation of diagenetic minerals and through the brittle deformation and fracturing of framework minerals (detrital or diagenetic) during burial. They can be readily detected by fluorescence microscopy because of their distinctive fluorescence emission colours. The presence of high abundances of oil inclusions in the gas or water zones of reservoirs have previously been used to detect palaeo oil columns or residual zones. Recent advances in analytical techniques and instrumentation mean that it is now feasible to obtain detailed geochemical data on the trapped oils, which can be directly compared with either reservoired oils or with putative source rocks.
Several previous studies have examined the molecular composition of oil inclusion. One important application of the analysis of these samples of palaeo-oil is to correlate and compare them with currently reservoired oils and deduce hydrocarbon charge histories.
This paper discusses a methodology for estimating permeability from well logs, based on conventional core and log data. The work was done on a small set of wells containing a glauconitic sandstone reservoir in the Barrow Sub-basin offshore, Western Australia. Core porosity and permeability data were used to determine porosity-permeability transforms and to subdivide the "greensand" into various groups within two sub-units. Electrofacies patterns and decision functions were determined to establish a link to permeability transforms in order to identify sandstone groups and to obtain porosity and permeability from well logs where cores were not available. Estimates of permeability were found to be more accurate than using other methods. In this technique, permeability transforms were obtained not only by considering unique relationships between porosity and permeability but also grain size and sorting et al. The results of this work have been encouraging and the study is now being extended on a regional basis.
In formation evaluation, it is generally essential to obtain realistic values of permeabilities from well logs because core-based permeability data are often not available either because of bore hole conditions or due to the high cost of coring. For many years, attempts have been made to estimate permeability from well logs. Much literature has been published on the subject and a number of methods and models are being used to achieve this goal. Two categories of equations are generally available. One category contains the so-called 'standard methods' such as Wyllie and Rose (1950), Timur (1968), Coates and Dumanoir (1973) and some modified forms of these. They are based on establishing empirical relationship (formulas or models) which are functions mainly of porosity, permeability, irreducible water saturation or clay content. However, none of these is generally applicable from field to field, well to well or even zone to zone without making adjustments to constants or exponents, or introducing compensations. Moreover, the accurate determination of irreducible water saturation and clay content from well logs is not an easy task. Alternatively, there are 'statistical methods' such as are described by Nicolaysen (1991), Sinha (1994), Johnson (1994) and others. They attempt to establish a direct statistical relationship between log responses and permeability, or use a data base to relate permeability to log responses on a field wide basis. The methods utilise relationships which are implicit in the data to arrive at results. No predetermined equations are required, and results are obtained by statistical inference.
The subject reservoir of this study is an extensive, marine transgressive, and glauconite-rich formation. It was deposited during a southward-progressing marine transgression over deltaic topset sands during the Early Cretaceous. The glauconitic sandstone is mineralogically complex. The main mineral components include quartz, glauconite, siderite, dolomite, calcite, feldspar, kaolinite, pyrite, and their alternation products. Quartz, glauconite, feldspar and siderite generally are the most abundant minerals and occur together in most of the Mardie lithofacies Porosity (helium injection) and permeability were determined on 139 core plugs on 4 wells cored in this area. They indicate that porosities are medium to high (from 13.9% to 29.7%), that permeability ranges from 0.01 md to 47 md throughout the sandstone in the two main sub-units and that there is poor correlation between porosity and permeability. Traditional methods for estimating permeability from log responses are not applicable in the Mardie Greensand.
Dr. Jack R. Nelson, SPE
Increased recovery from existing, marginal and partially depleted oil fields has been the objective of many operators over the years. Conventional step out drilling, redrilling, and reentering are often options to consider in these cases. Improvement in recoverable production may be obtained, although economics may be questionable in many cases.
Horizontal drilling technology has been widely and successfully applied around the world for the recovery of heavy oil, light oil and gas. Impressive technical successes have been achieved in horizontal technology through a variety of improvements in tools, and experience gained over the past several years.
Utilizing horizontal drilling technology in developing and increasing productivity of marginal fields has improved economics in most instances. Also it has provided solutions to the recovery of oil from inaccessible areas in reservoirs such as undrained fault blocks. After abandoning old wells, the existing wellbores are re-entered and horizontally redrilled through the pay zone.
The primary objective of a horizontal well is to increase the wellbore contact with one or more reservoirs. Often this contact will be limited to a specific interval in the reservoir. There are factors and limitations that determine the success of horizontal wells.
This paper will discuss the selection of reservoir candidates, planning options, re-entry drilling, and well completion of the horizontal candidates.
In recent years, horizontal drilling techniques have been successfully used worldwide in a variety of situations. The impressive technological and economic success achieved has resulted from new and improved tools, better methodology, and a wide background of experience that has been developed over time.
Horizontal drilling is being commonly used today as a technique for improving recovery and productivity from marginal or partially depleted fields because it offers the benefit of greatly improved drainage patterns from a minimum of well bores. This application may take the form of re-entering existing well bores and drilling a horizontal hole through a window milled in the casing or new wells may be drilled as necessary. Variations in application are many. The horizontal well bores may be used to improve existing well patterns or, to reach inaccessible areas of the fields or, to permit economic production levels from reservoirs in advance stages of depletion which are subject to water or gas coning.
Benefits of Horizontal "Re-Entry" Drilling
Horizontal wells must be considered today as an attractive way of developing reserves. Drilling horizontally is not an objective itself, the objective is increased production and reserves. A comparison can be made between the productivity of a horizontal vs. a vertical well using different parameters such as spacing, permeability and length of horizontal sections to more easily visualize the capability of horizontal wells for improving production and increasing reserves. These comparisons are based on ideal considerations seldom encountered in real reservoirs but they serve to illustrate the advantages of horizontal drilling.
The comparison will start with spacing (Fig. 1) which is based on the calculation formula of Dr. Joshi. Assuming that the net pay is 50 ft., the horizontal permeability is equal to the vertical permeability, the wellbores have radii of 3.5 in., and that the horizontal sections are 1600 ft., the productivity of each horizontal well is almost 10 times higher than the vertical well for a vertical-well-drainage area of 40 acres.
Permeability anisotropy in a coal seam in the Bowen Basin has been measured by a multiple well interference test. The degree and orientation of the anisotropy was apparently influenced by coal structural features on various scales. Simulations of the field observations using a two-phase dual porosity model confirmed the single-phase interference test analysis, and also simulated various aspects of the seam response to subsequent stimulation treatments involving two-phase fluid injections. The influences on reservoir response of reservoir heterogeneity, relative permeability and flow localisation are discussed with respect to the application of continuum modelling concepts.
Naturally occurring fracture systems in coal occur on a range of scales. The fractures have much higher fluid conductivities than the coal matrix and generally control the fluid transport properties. The most pervasive natural fracture system is the cleat system, formed mainly in bright coal by orthogonal sets of face and butt cleats, lying in planes normal to bedding. These define a blocky structure within the coal, which because of the more planar and continuous nature of the face cleat relative to the butt cleat, can result in strong permeability anisotropy This is reflected in measured anisotropy ratios as high as 17:1 in the plane of the seams.
Permeability is one of the most important factors controlling the production of coalbed methane (CBM), and efficient stimulation is generally required to obtain adequate gas production rates. Hydraulic fracturing is the commonly applied stimulation method. An alternative technique, openhole cavity completion, may be successful if conditions are suitable. In either case, the presence of horizontal anisotropy in the permeability field can strongly affect the efficiency of the stimulation, and needs to be considered in the stimulation design and the production well layout.
In assessing the likely orientation of permeability anisotropy in a coalbed methane reservoir, it is often assumed that the major permeability axis will parallel the face cleat direction which in turn is assumed to parallel the direction of the major horizontal principal stress. The direction of the major principal stress might be estimated by measurement of hydraulic fracture orientation in a minifrac test in the bounding sediments of the seam, and the major permeability axis inferred from the stress direction. Alternatively, core orientation methods may provide the cleat direction directly. However, these methods may not account for other influences on permeability orientation, such as the effect of broader scale fracture systems, or the coupled effects of the structures with the stress regime and pore fluid pressure gradients.
During an investigation and trial of stimulation by cavity completion carried out in the Bowen Basin, detailed reservoir response to the process was investigated. Reservoir characterisation undertaken before stimulation included direct measurements of permeability anisotropy by interference testing in multiple observation wells. Subsequently, during stimulation operations, both water and air were injected using a range of rates, pressures and durations, including highly dynamic, short duration events. Data from the active wells and the observation wells were continuously recorded throughout the operations. Analysis of permeability anisotropy based on the response of the observation wells was carried out using both standard analytical methods and numerical simulations.
This paper presents the field data in the context of the target seam conditions and compares estimates of permeability anisotropy from the standard analysis of the single-phase interference tests with the values obtained by numerical simulation of the complex two-phase injection history. The limits of continuum analysis in terms of the scale effects of coal structures, mechanical-fluid flow coupling and flow localisation and the implications for coalbed methane reservoir characterisation are discussed.
A number of tools are available for production improvements for wells where the cost of workover rigs cannot be justified or where workover rigs are unavailable. Recent literature has described some through tubing and rigless type workover innovations. This paper presents case histories explaining the use of production logging, coiled tubing, small bridge plugs, cement packers, acidizing and oriented perforating methods that resulted in excellent gas and oil production increases. Significant savings were experienced when compared to more conventional rig supported workovers.
Cement packers placed by coiled tubing and oriented through tubing perforating have been used in several cases to restore inactive wells to commercial production rates. This paper describes two such attempts. In another case, extraneous water production was identified with a production log and shut off with a simple bridge plug setting. This was followed by acid stimulation of the gravel pack to restore the damaged interval to good gas rates. A third case is also presented to show several problems that were encountered in an older well.
In order to select the appropriate technique and achieve the best results, a clear understanding of the problems, the objectives, and the available tools is needed for each case. This was accomplished by use of a multi-disciplinary team of various operating company and service company professionals involved in, the design and field operations to thoroughly review each proposal.
VICO Indonesia operates several oil and gas fields in an area of East Kalimantan approximately 140 kilometers north of the city of Balikpapan (Fig. 1). These fields are operated under a production sharing contract with Pertamina, the Indonesian national oil company. VICO is the operator of a joint venture that began in the late 1960's and discovered commercial oil and gas in early 1972.
Today the production rates are approximately 1.7 billion cubic feet (Bcf) gas, 40,000 bbl of condensate and 30,000 bbl of oil per day from VICO's four major fields. Gas is transported and sold through the liquification (LNG) plant at Bontang, and the liquids are blended and sold via the tanker terminal at Santan.
Badak, the largest and oldest field, has now been completely developed by drilling. Because of the large number of reservoirs penetrated by wells in this field, workover operations will continue for many years to recomplete into shallower zones and repair existing completions.
Now, in efforts to maximize the use of all wellbores and considering cost containment issues, production engineers at VICO have designed and performed several unique work programs that utilize rigless methods at a cost of about one-third the cost of similar rig supported workovers. These programs involve the use of production logs, coiled tubing, special cementing techniques, oriented perforating, inflatable packers, acidizing cement packers, computer modelling, small diameter tools, etc.
Generally, very good success has resulted from the overall program. Gas production was increased by 130 million cubic feet per day (MMcf/D) and oil rates improved significantly in 1995. A few unexpected problems were encountered and these are also discussed.
TDT Log, Coiled Tubing cement Packer, Oriented Perforating - Badak Well number 121
The original completion for Badak well number 121 was a dual gas well. By 1993 both zones had watered out, but interest in a zone behind casing led to a thermal decay time (TDT) log survey (Fig. 2). This survey showed that the three zones in the B-12 reservoir were not uniformly depleted since the middle interval was wet while the upper and lower sections contained gas.
A new technique has been developed that allows determination of the resistivity of a pristine sample of irreducible water trapped during oil accumulation, This fluid inclusion technique, termed ROI, is directly applicable to the evaluation of oil accumulations where the salinity of present day formation waters below the OWC differs from that of irreducible water trapped during oil accumulation.
Determination of oil saturation for calculation of oil reserves is critically dependent on the resistivity of formation water (Rw). Water saturations calculated from logs require an Rw value for irreducible water in the oil zone. In conventional log analysis the formation water salinity in the oil zone and therefore the Rw is assumed to be the same as that below the OWC. This relies on the assumption that the water below the OWC has not changed following oil charge.
Irreducible water is trapped with oil in microscopic fluid inclusions within reservoir grains. Resistivity of this water can be derived from an ice melting temperature using the correlation between colligative and transport properties of aqueous solutions. Measurements are made on core or cuttings samples from the oil zone and exclude contamination from mud filtrate invasion.
Water below the OWC may change after oil charge in basins which are exposed at the land surface. This may allow recharge of meteoric water, potentially resulting in lower salinity water below the OWC than in the oil zone e.g. in more shoreward oil filled reservoirs underlain by freshwater aquifers in the Gippsland Basin, calculated water saturations using the salinities from water below the OWC are inconsistent with RFT, capillary pressure and production test data. The opposite situation can also occur where tectonic movements cause relatively deep saline water to flow into reservoir rocks below the OWC.
In these situations the water below the OWC will differ in salinity and Rw from irreducible water in the oil zone which is shielded from later flow of formation water by high oil saturation.
The timing of changes in hydrology relative to oil charge has major implications because use of an inappropriate formation water resistivity value can result in incorrect reserves estimation. Decisions regarding field development are linked to reserves estimates and accurate Rw values are essential.
Current Methods for Determination of Rw
The most direct way of finding water resistivity (Rw) is to obtain a sample of formation water and measure its resistivity. However, this is seldom possible, as formation water samples are usually contaminated by mud filtrate. Rw is therefore usually calculated by one of two methods:
1. SP method
2. Archie equation
Reliable determination of oil saturation from logs requires a determination of Rw from a measurement directly on a sample of the irreducible water.
Calculated Rw relies on a number of assumptions which may result in erroneous values - the SP method does not work for oil based muds and does not give correct estimations of Rw in hydrocarbon bearing zones while the Archie equation method only works in clean, water-bearing reservoirs and is typically unreliable in highly fractured or vuggy reservoirs.
Capillary Pressure and Relative Permeability
For practical purposes, the value of the irreducible or minimum water saturation in the oil zone is usually assumed to represent the interstitial water content of the pay section of the reservoir. Interstitial water in this zone is held in place by capillary forces, and flow differentials will not remove it. P. 137