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
VICO's major gas fields in East Kalimantan, Indonesia contain in excess of 2,000 individual gas reservoirs ranging in depth from 4,000 feet to 15,000 feet that have been penetrated by almost 500 wells. These reservoirs are located in a geologically complex deltaic environment and, therefore, vary drastically in size, permeability, and compositional make-up.
Because of the large number of wells and reservoirs, a Depletion Planning (DEPLAN) program was designed, developed, and implemented by VICO to assist managing deliverability, current and future wellbore optimization, and compression requirements necessary to meet gas sales commitments. DEPLAN is a computerized field management program linked to VICO's PARM database. It assembles, organizes and analyzes data using standard engineering principles to optimize field depletion planning. The program utilizes volumetric depletion methodology for gas reservoirs and generates individual well deliverability by combining inflow and outflow equations. The results of simulation models can be entered into DEPLAN as necessary.
The gas requirement schedule and reserves are input parameters, with the model output essentially represented by field gas deliverability predictions and generation of work programs. Since it's inception in 1990, DEPLAN has proven to be a valuable tool to assist in reservoir management and development of complex multilayered gas fields.
VICO Indonesia, as a Production Sharing Contractor to PERTAMINA, operates four major gas fields; Badak, Nilam, Mutiara and Semberah which are located in the Mahakam delta of East Kalimantan, Indonesia (Figure 1). These fields provide an average daily supply of approximately 1.5 Bscf/D to the Bontang LNG plant and Kaltim Fertilizer Plants. The four fields consist of more than 2,000 gas reservoirs with the majority occurring in the form of distributary channels and mouth bars. Currently, 467 wells have been drilled and completed in these fields as dual, dual selective or single completions. Typical reservoir and well completions are shown in Figure 2.
Because of the large number of reservoirs and wells with multiple completions, a specific computerized Depletion Planning (DEPLAN) program was designed by VICO to assist in the managing the development of these fields. This paper describes the DEPLAN program and explains its' application in the optimization of development of the Nilam field.
Description of Depletion Planning Model
The computerized DEPLAN program is a field management tool designed, developed, and implemented by VICO to assemble, organize and analyze data using standard petroleum engineering principles to optimize field depletion planning. The program utilizes volumetric depletion methodology for gas reservoirs and generates individual well deliverability projections by combining inflow and outflow equations.
DEPLAN is automatically linked to VICO's engineering, geological, and operations (PARM) database for extraction of numerous tables of current and historical data. Formatted data entry screens are provided for input of necessary criteria such as schedules for gas rate requirement (demand), well producing priority, and well prognosis as well as parameters for timing of certain actions, range limitations for completion, and compressor or facilities capacities. The program output options are essentially presentations of field gas deliverability and production predictions in addition to required work programs over time. DEPLAN's operational flexibility facilitates the evaluation of various producing scenarios with respect to time.
X. Chen, SPE, Australian Petroleum Cooperative Research Centre, CSIRO Petroleum & Monash University, Melbourne, Australia; C.P. Tan, SPE, Australian Petroleum Cooperative Research Centre, CSIRO Petroleum, Melbourne, Australia; and C.M. Haberfield, Monash University, Melbourne, Australia
Mechanically-induced wellbore instability can be managed by determining the critical mud weights that provide sufficient wellbore wall support to counteract the redistribution of stresses resulting from the creation of the wellbore. The critical mud weights are mainly dependent on the in-situ stress regime, in-situ pore pressures, wellbore direction and inclination, and formation properties and drainage conditions. In this paper, a review of the various failure mechanisms and the effects which the mechanical factors (attributes) have on wellbore stability are presented. The review includes a summary of the typical ranges of the key attributes as determined from the literature. A series of sensitivity analyses which demonstrate the influences of these attributes on wellbore stability are presented and discussed. The analyses are based on shale properties and in-situ stress regimes typical of the North West Shelf of Australia. Finally, guidelines for wellbore stability analysis for practical well design are described.
In the current climate of deeper reservoir exploration and increased exploitation of offshore reservoirs in the world's sedimentary basins, costs of production are significant. In Australia, nearly 90% of petroleum reservoirs are found offshore. The cost of drilling a well in such an environment can be up to A$10 million, so the chances of commercial success are not high. However, an acceptable profit margin can still be achieved by drilling directional wells from a central platform so that the number of drilling platforms can be reduced significantly. This incentive of reducing investment costs has led to the continuing development and application of directional drilling technology. However, one of the main potential problems associated with the application of directional drilling is wellbore instability. Such instability results in not only additional cost but also significant drilling delays and abandonment of wells. An estimate of US$500 million is lost each year worldwide, directly or indirectly caused by wellbore instability. Therefore, in order to fully obtain the benefits of the directional drilling technology, wellbore stability analysis has been of increasing demand in the planning stage of the wells.
Nearly all wellbore instability problems occur in the weaker rock formations, predominantly shales. The awareness of high-risk shale formations has led to considerable research on shale mechanics, which involves either chemical or mechanical investigation or a combination of both. Although many instances of instability result from a combination of both mechanical and chemical instability, mechanical factors play a dominant role in wellbore instability during the drilling phase of operations. For example, borehole instability is observed even with the most inhibitive drilling fluids, e.g. oil-based mud. Also, mechanically-induced instability caused by high in-situ stresses in vertical wells can create a more or less severe environment for inclined wells, depending on the direction and inclination of the wells with respect to the stress field. Significant effort, therefore, has been put into mechanically-induced instability studies.
In this paper, firstly, a review of the various failure mechanisms and the factors (attributes) which affect wellbore stability is presented. The review includes a summary of the typical ranges of these key attributes as determined from the literature. A series of sensitivity analyses that demonstrate the influences of these attributes on wellbore stability are then presented and discussed. The analyses are based on shale properties and in-situ stress regimes typical of the North West Shelf of Australia. Finally, guidelines for wellbore stability analysis for practical well design are described.
Wellbore Failure Mechanisms
Drilling a well in a formation changes the initial stress state and causes stress redistribution in the vicinity of the wellbore. The redistributed stress state may exceed the rock strength and hence, failure can occur.
G.B. Hatcher, Australian Petroleum Co-operative Research Centre (APCRC), CSIRO Division of Petroleum Resources, H. Chen and S.S. Rahman, SPE, APCRC, Centre for Petroleum Engineering, University of New South Wales, P.F. Hogg, West Australian Petroleum Pty. Ltd.
When exploiting hydrocarbon reserves in lithologically and petrophysically complex glauconitic sandstones, potentially damaging fluid/rock and fluid/fluid interactions must be thoroughly investigated. This paper reports on the first phase of a comprehensive, multi-disciplinary study of such interactions conducted on samples from the Saladin field, located on the offshore North West Shelf of Australia. Core floods indicate that the formation is not susceptible to significant damage during the flow of simple brines. However, chemical analysis of core flood effluents after periods of stasis indicate continuing interactions between introduced fluids and fluids resident in the large volume of microporosity. Awareness of such delayed interactions will be important in restored state core analysis and when evaluating the damage potential of more complex fluid systems. The reservoir was found to suffer extreme damage on exposure to freshwater. The sum of evidence suggests that swelling of glauconitic smectite is the underlying cause of the damage, with pore throat plugging by mobilised glauconitic smectite and non-expandable glauconitic clays the probable damage mechanism. Saturation with calcium chloride solutions prevented water shock damage.
The risk of significant impairment of a reservoir's capacity to produce hydrocarbons must be assessed when planning any field operation which may impinge on the reservoir. The basis for this assessment is an understanding of reservoir behaviour when contacted by the fluids used in these operations. This allows the potential damage mechanisms to be identified and the underlying causes to be determined. Appropriate preventative and/or remedial procedures can then be designed.
Formation damage mechanisms and causes in many reservoir types have been extensively studied and significant advances made in understanding how and why damage occurs. Refs. 1 through 3 provide good overviews of the subject. However, complex lithologies, such as those containing unusually high clay concentrations or having dual porosity systems have received less attention. Such reservoirs may still have the potential to produce unpleasant surprises during field operations.
Glauconitic sandstones are one such complex lithology, having both a high clay content and a dual porosity system. They contain abundant, iron-rich clay particles aggregated into grains whose microporosity can represent a significant proportion of the total porosity. Fluids flowing through the intergranular pore system may largely bypass this micropore volume, but remain in communication with its fluid content across the porous glaucony grain surfaces (Fig. 1). Potentially damaging fluid/rock and fluid/fluid interactions may take place as the two fluid volumes equilibrate during the static periods which are a normal part of oilfield operations. Conventional, continuous flow core floods may fail to identify such risks.
This paper reports the results of a series of modified aqueous core floods conducted to investigate these phenomena. During the floods, flow was periodically interrupted to allow equilibration between the fluids in the macropore and micro-pore systems. Core flood effluents were characterised by pH measurement and chemical analysis. Effluents were filtered to capture any produced solids for petrographic characterisation The core plugs themselves were subjected to petrographic examination before and after exposure to the introduced fluids.
Formation Damage Mechanisms and Causes It is not the purpose of this paper to present a review of formation damage research. However certain key concepts need to be outlined and some terms defmed. Since the specific damage issues investigated involved clays and their interactions with introduced fluids, the following discussion is limited to concepts pertinent to clay-related formation damage.
Water saturation (Sw) in shaly sand formations has been a subject of debate for many years and several equations have been introduced for the estimation of Sw. In the present study, several equations for the estimation of Sw are applied in the Late Carboniferous - Early Permian kaolinite-bearing Tirrawarra Sandstone, an important oil reservoir in the Cooper Basin. The results from Archie and Waxman-Smits equations display a good correlation with measured core water saturation.
Plots of water saturation from the Archie equation with water saturation from the other equations show that the Archie and Waxman-Smits equations are approximately the same (r2=98%). As can be expected, due to the low cation exchange capacity (CEC) of Tirrawarra Sandstone, the second part of the Waxman-Smits equation concerning shale conductivity is very small. As a consequence, the values of Sw from the Waxman-Smits equation are very close to those from the Archie equation. Petrographical studies indicated that kaolinite patches in the Tirrawarra Sandstone are water wet. In this case, the formation resistivity is a function of formation water in macro-porosity and irreducible water associated with kaolinite micro- porosity. In other words, when kaolinite is electrically inert, the whole rock can be considered as a clean sandstone which obeys the Archie law. Because resistivity logs cannot recognise free water within the macroporosity from bound water associated with clay minerals, calculated water saturation includes both free and irreducible water. As the irreducible water associated with kaolinite minerals is not expelled during production, some intervals of kaolinite-rich sandstones, which may never produce water, may be bypassed as non-productive zones.
A new equation is introduced for estimation of effective water saturation. The equation is based on the integration of resistivity and sonic logs with image analysis data for wells in the Moorari and Fly Lake fields, where obtaining the volume of clay is difficult and unreliable. This equation, which reduces calculated water saturation by about 10% for the Tirrawarra Sandstone, is likely to be applicable to other kaolinite-bearing sandstones.
Water saturation (Sw) is one of the most important petrophysical parameters required for reserve calculation. In clean sandstones, estimation of water saturation is rather simple due to the lack of electrically-conductive materials such as clays. The presence of clays in the shaly sandstones which display high conductivity (Ref. 1) makes estimation of water saturation complicated. In this paper, factors affecting conductivity of shaly sandstones are reviewed and some of the common equations which are used for calculation of water saturation are applied to the Tirrawarra Sandstone and a new equation to estimate water saturation in kaolinite-rich sandstones is introduced.
Electrical conductivity of a rock depends on several variables including, conductivity of rock components, conductivity of pore fluid, fluid saturation and formation factor (F). In clean sandstones, the conductivity of rock components is zero and electrical conductivity is a function of conductivity of pore fluid, fluid saturation and formation factor. In shaly sand formations, the electrical conductivity of rock components can not be considered zero, as clay minerals provide additional conductivity (Ref. 1). In these sorts of formations, conductivity of the clay minerals should also be estimated.
Formation Factor. Formation factor was first introduced by Archie (Ref. 2) and defined as the ratio of the conductivity of brine to the conductivity of fully saturated clean sandstone:
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.
This paper, which uses large amount of data, discusses the wettability of formations and reservoirs and its characteristics by analyzing the surface tension and surface electrostatic force of different rock minerals and pore fluids, the effect of preferential wetting and preferential adsorption on reservoir wettability, and the change of reservoir wettability after water flooding. On the basis of the above discussion, three-state model of pore fluid distribution are divided into three types.
Surface Dynamic Nature of Rock - Forming Minerals, Clay and Fluids
i. Rock-forming minerals
Liquids and solids have surface tension. All the experimental materials indicate that solids have larger surface tension than liquids. The mineral grains which form reservoirs are made up of non-uniform ions with different electric properties. All the ions on the surfaces of the grains have an asymmetrically electric field as well as an asymmetrically gravitational field. These asymmetrical fields make the grain surfaces form a weak electromagnetic field. Now we shall analyze the commonest surface layer.
Take the commonest - quartz for example. The crystal structure of - quartz is shown in Fig. 1. It is usually known as silicon-oxygen tetrahedron. From this we can know:
A. The tetrahedron surface is oxygen
B. The proportion between silicon and oxygen in SiO2 is 1:2.
C. Because of the above characteristics of the surface structure, the quartz surface is made to be a negative electric field. It is proved by calculation that the force of unit negative charge at the distance b ( 0) from the surface of - quartz is
where - diameter of O2 - f - Coulomb factor
e - Charge of an electron
In the gap of the frame structure formed by silicon-oxygen tetrahedrons and aluminium-oxygen tetrahedrons, these are full of potassium or sodium ions sometimes Calcium or barium ions (See Fig. 2). Such crystal characteristics, in addition to the actions of potassium ions, decrease the negative field intensity of the crystal surface and make the negative field intensity of Feldspar surface less than that of quartz's.
Calcite also exists in rock-forming materials of sandstone reservoirs. Analyzing of crystal structure, the polarity of calcite is smaller than feldspar's. Since water is a molecule with strong polarity, general speaking minerals which have strong field intensity have strong hydrophilic nature. Daqing Oilfield made an experiment by use of a crystal of feldspar and quartz and the same quantity of oil and water. The result is that the contact angle of oil on the quartz chip is smaller than that on the feldspar's. This indicates that quartz has a stronger hydrophilic nature than feldspar.
The fluids in the pore space are usually oil, air and water.
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.
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.