AU2008201132B2

AU2008201132B2 - Method of identifying compartmentalization of a reservoir

Info

Publication number: AU2008201132B2
Application number: AU2008201132A
Authority: AU
Inventors: Robert Charles Davis; Bruce Rennie James
Original assignee: Woodside Energy Ltd
Current assignee: Woodside Energy Ltd
Priority date: 2007-03-23
Filing date: 2008-03-11
Publication date: 2013-04-04
Anticipated expiration: 2028-03-11
Also published as: AU2008201132A1

Abstract

Abstract A method of identifying compartmentalization of a reservoir is described. The method 5 comprises the steps of a) obtaining a plurality of fluid samples of a reservoir, the plurality of fluid samples taken from a plurality of locations in the reservoir; b) analyzing the plurality of fluid samples to obtain a plurality of compositional data points, each compositional data point providing a representation of the concentration of carbon dioxide present in a given fluid sample; c) analyzing the plurality of fluid samples to obtain a plurality of isotopic data points, .0 each isotopic data point provides a representation of the stable isotope ratio of carbon dioxide or oxygen present in a given fluid sample; d) plotting the plurality of compositional data points against the plurality of isotopic data points for each of the plurality of locations; and, e) analyzing the proximity of the plotted plurality of compositional and isotopic data points as an indication of the degree of compartmentalization of the reservoir. Fluid Sampling Gas Analysis Data Plotting j 106 Assess Level of Compartmentalization 108 Figure 1

Description

METHOD OF IDENTIFYING COMPARTMENTALIZATION OF A RESERVOIR FIELD OF THE INVENTION 5 The present invention relates to a method of identifying compartmentalization of a reservoir using compositional and isotopic analysis of fluid samples collected from the reservoir. The present invention relates particularly, but not exclusively to a method of identifying compartmentalization of a hydrocarbon reservoir. 10 BACKGROUND ART Unexpected reservoir compartmentalization is one of the most serious and common problems facing offshore development of oil and gas. Depending on the field, compositional differences between fluids in separate compartments can exist for a number of reasons such as differential secondary alteration (for example biodegradation, water washing, gas flushing), 15 and differential mixing of fluids from more than one source rock. When oil and gas reservoirs are unexpectedly compartmentalized, part of the hydrocarbon present in the reservoir may not be recoverable using the planned production wells. Additional wells are then required to drain isolated compartments and the drilling of such additional wells can be cost prohibitive in an offshore environment. 20 Several prior art techniques have been developed to predict compartmentalization. Information concerning reservoir connectivity in fields before production starts may come from wireline logs, seismic data, production testing, production histories, and/or reservoir descriptions (from core, cuttings and log data). Such prior art techniques use pressures 25 measured in appraisal wells, fluid compositions, transient response from well testing, interference testing, or interpretation of seismic and geological data. All of these prior art techniques can yield ambiguous results, and some are prohibitively expensive. The composition and isotopic signature of mud-gas samples and/or reservoir fluids obtained during a drilling operation is often used to determine the connectivity of hydrocarbon 30 reservoirs. These so-called "reservoir geochemistry" techniques rely on the assumption that fluid samples in communication in geological time should have identical chemical and isotopic signatures. One form of these prior art methods relies on a comparison of the compositional (mole percent) and stable carbon isotope (delta-13C) signature of the gaseous -2 hydrocarbons (methane, ethane, propane, butanes, pentanes). If two fluid samples have different gaseous signatures, then it is concluded that the samples have been taken from areas of a reservoir which are separated by a barrier. Such prior art reservoir characterization methods suffer from several disadvantages. For example, they have little or no use in 5 situations where all the hydrocarbons in a given reservoir are compositionally the same. In this case, prior art reservoir fluid characterization techniques provide no useful information on compartmentalization. There remains a need for a compositional and isotopic analysis method which provides a more 10 reliable indication of reservoir compartmentalization. SUMMARY OF THE INVENTION According to one aspect of the present invention, there is provided a method of identifying compartmentalization of a reservoir comprising the step of: 15 a) obtaining a plurality of fluid samples of a reservoir, the plurality of fluid samples taken from a plurality of locations in the reservoir; b) analyzing the plurality of fluid samples to obtain a plurality of compositional data points, each compositional data point providing a representation of the concentration of carbon dioxide present in a given fluid sample; 20 c) analyzing the plurality of fluid samples to obtain a plurality of isotopic data points, each isotopic data point provides a representation of the stable isotope ratio of carbon dioxide or oxygen present in a given fluid sample; d) plotting the plurality of compositional data points against the plurality of isotopic data points for each of the plurality of locations; and, 25 e) analyzing the proximity of the plotted plurality of compositional and isotopic data points as an indication of the degree of compartmentalization of the reservoir. To improve sampling precision, step a) may comprise the step of obtain one or more fluid samples from a plurality of locations in the reservoir. Preferably, the plurality of locations in the reservoir may be a plurality of appraisal wells. In one embodiment, the plurality of fluid 30 samples is obtained from a plurality of depths within each appraisal well.

-3 Preferably, the method further comprises the step of recording the pressure and temperature conditions of the reservoir during the step of obtaining the plurality of fluid samples so that the compositional data points can be normalized as a function of reservoir conditions. 5 Steps b) and c) may be repeated to generate error bars indicative of a level of analytical precision and the error bars are assigned to each compositional or isotopic data point. Step a) may comprise fluid sampling using a down-hole tool including one or more sampling chambers or surface sampling of fluid from a producing field or direct sampling of gases 10 entrained in drilling mud. Alternatively, step a) may comprise the step of collecting canned cuttings and steps b) and c) are conducted by analyzing the head space gas which exsolves from the canned cuttings. Preferably, the reservoir is a hydrocarbon reservoir. 15 According to a second aspect of the present invention there is provided a method of identifying compartmentalization of a reservoir substantially as herein described. 20 BRIEF DESCRIPTION OF THE DRAWINGS In order to facilitate a more detailed understanding of the nature of the invention several embodiments of the present invention will now be described in detail, by way of example only, with reference to the accompanying drawings, in which: 25 FIG. 1: is a flow chart which illustrates the steps undertaken in performing the method of the present invention; and, FIG. 2: is a plot of carbon dioxide content of the gas (in mol%) on the y-axis versus stable isotope composition of the carbon dioxide (delta-13C in parts per thousand ("ppt") or per mille) on the x-axis for three fluid samples taken from three separate locations 30 in an oil field.

-4 DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS Particular embodiments of the method of identifying compartmentalization of a reservoir using carbon dioxide concentration and stable isotope composition are now described in the context of a hydrocarbon reservoir. The present invention is applicable to the identification of 5 compartmentalization in other fluid reservoirs such as water aquifers or in coal-bed seam methane. The terminology used herein is for the purpose of describing particular embodiments only, and is not intended to limit the scope of the present invention. Unless defined otherwise, all technical and scientific terms used herein have the same meanings as commonly understood by one of ordinary skill in the art to which this invention belongs. In 10 the drawings, it should be understood that like reference numbers refer to like members. The term "isotope" refers to any of two or more forms of a chemical element, having the same number of protons in the nucleus and, hence, the same atomic number, but having different numbers of neutrons in the nucleus and, hence, different atomic weights. Throughout this 15 specification, isotopes are specified by the name of the particular element (implicitly giving the atomic number), followed by a hyphen and then the mass number. For example, carbon 12 (C-12) is a stable isotope in which the carbon atom has 6 protons and 6 neutrons in its nucleus whereas carbon-13 (C- 13) refers to a carbon atom having 6 protons and 7 neutrons in its nucleus. C-13 is also a stable isotope but C-14 is radioactive. 20 Because the chemical behavior of an atom is largely determined by its electronic structure, isotopes are known to exhibit nearly identical chemical behavior, with one main exception. Due to their larger masses, heavier isotopes tend to react somewhat more slowly than lighter isotopes of the same element. The relative percentages of isotopes present in a fluid sample 25 can be distinguished by mass spectrometry or infrared spectroscopy. The stable isotope ratio of carbon dioxide is expressed as "S8 3 C" or "delta-13C" which is the difference between the C-13 composition of a sample relative to the C-13 composition of an international standard carbon isotope reference (the Pee Dee Belemnite or "PDB", namely, the C-13 composition of a belemnite fossil from the Cretaceous Pee Dee Formation in South Carolina, USA). 30 With reference to FIG. 1, the steps of the method will now be explained. The method begins with step 100 in which a fluid sample is taken from at a location within a reservoir. This step -5 is repeated such that a plurality of fluid samples is taken from a plurality of locations in the reservoir. Any number of samples can be taken with at least one such sample preferably being collected for each appraisal well. In a new field, the plurality of locations corresponds with the location of a plurality of appraisal wells with at least one fluid sample being taken per 5 location. More than one fluid sample may be collected per appraisal well. For example, if there are multiple intervals in a reservoir, a fluid sample may be taken at a plurality of depths within the same appraisal well. Next, in step 102, each fluid sample is analyzed using either laboratory or field equipment to 10 generate data points which represent the percentage carbon dioxide present (expressed in mol%) in each given fluid sample and to obtain the stable isotope ratio (delta-13C) for the carbon dioxide present in each given fluid sample. The pressure and temperature conditions of the reservoir are recorded during step 100 so that the compositional data points can be normalized as a function of reservoir conditions. The stable isotope ratios are determined 15 using mass spectrometry or other suitable procedure well known to a person skilled in the art. Ideally, the sampling precision is determined by analyzing multiple samples from the same reservoir zone in the same well, and multiple sub-samples of the same sample, and the analytical precision is determined by analyzing the same sample multiple times. 20 Next, in step 104, the data points generated from step 102 are optionally tabulated before being plotted an x-y plot in which the carbon dioxide content (in mol%) data points are plotted on the Y-axis with the stable isotope ratios (delta-I 3C) being plotted on the X-axis for each of the plurality of locations within or across the reservoir. It is equally possible for the carbon dioxide content data points to be plotted on the X-axis with the stable isotope ratios 25 being plotted on the Y-axis. Error bars determined from analyzing multiple samples in step 102 are assigned to the data points. Next in step 106, the level of compartmentalization of the reservoir is assessed based on analyzing the proximity of the data points plotted in step 104, with reference to the 30 experimental error. The distance between data points which are representative of various locations across or within the reservoir is indicative of the degree of communication between compartments. Reservoirs that are disconnected may have different compositional levels of -6 carbon dioxide and/or different stable carbon isotope ratios. Consequently, the presence of a barrier within the reservoir is indicated when the data points do not lie in close proximity to each other. Conversely, when the data points plotted in step 104 lie in close proximity to each other this reflects compositional homogeneity which is supportive of good 5 communication within the reservoir, suggesting that there is little or no compartmentalization present between these locations. By way of example, FIG. 2 illustrates the results generated using the method of the present invention for a field which is now in production and where reservoir connectivity is known. .0 More specifically, FIG. 2 shows actual data for fluid samples taken from three locations in the field, the three locations being designated as WLI, WL2 and WL3. The data points plotted for two of the well locations (namely, WLl and WL2) are located in close proximity in FIG. 2 as a result of the fluid samples collected from these well locations having very similar carbon dioxide concentration and delta-13C C02 isotope ratio. This demonstrates a high probability L 5 that WL 1 and WL2 are located in the same compartment. With further reference to FIG.2, the data point for the fluid sample taken from WL3 has also been plotted on FIG. 2, and this data point lies at a distance remote from the data points plotted for WLI and WL2. This demonstrates that WL3 is located in a separate compartment !0 of the reservoir to the compartment from which the WL1 and WL2 fluid samples were collected. This correlates with the actual behavior demonstrated during production of the field from which the data points of FIG. 2 were taken. Without wishing to be bound by theory, the carbon dioxide composition is a more robust 25 indicator of compartmentalization than hydrocarbon (ethane, methane, propane, butane or pentane) composition as the carbon dioxide composition is independent of the type of hydrocarbon present in the reservoir. Differences in the isotopic composition of a fluid sample may arise either from isolation of different parts of the reservoir during filling of the reservoir or as a result of a secondary process acting differently upon the fluid in different 30 parts of the field. In circumstances where there is a single source kitchen for hydrocarbon gas and no applicable secondary alteration process, traditional prior art reservoir characterization techniques (which rely on hydrocarbon signatures) will show no difference in -7 either the hydrocarbon composition or the delta-13C isotopic values of hydrocarbons in isolated compartments of the field. In contrast, the carbon dioxide composition and the delta 13C isotopic values associated therewith can bear witness to the presence of multiple, isotopically distinct sources even where there is only a single source of hydrocarbon gas. 5 Carbon dioxide often displays large variations in either concentration and/or stable carbon isotope (delta-13C) ratio where hydrocarbon gases (methane, ethane etc) do not, thus revealing compartmentalization that is obscured using data from conventional hydrocarbons alone. Carbon dioxide isotopes are thus able to identify more subtle compartments than is possible using hydrocarbon isotopes alone. -0 Carbon dioxide has a number of properties which make it counter-intuitive to elect to use it as a tool for predicting reservoir compartmentalization. First, it is highly reactive and slow to reach chemical equilibrium which would make it appear unsuitable as an indicator of compartmentalization. Carbon dioxide is a relative large, dense molecule which is highly .5 soluble in water and which diffuses more slowly through hydrocarbon fluids in the subsurface. Second, in many parts of the world hydrocarbon based geochemistry works reasonably well in predicting compartmentalization. However, in offshore Australia, there are many cases where hydrocarbon based geochemistry does not work. Third, while it is a common occurrence in offshore Australia, for example gas fields off the northwestern coast 0 contain >10 mol% of carbon dioxide, gas samples in parts of the deepwater Gulf of Mexico contain only a fraction of 1 mol% carbon dioxide and are relatively insignificant. As a result, carbon dioxide concentration are too low to be able to analyze for 13C C02 isotopes. The present invention is based in part on a realization that the reactivity of carbon dioxide is 25 an advantage not a disadvantage. Without wishing to be bound by theory, the reactivity of carbon dioxide with its immediate environment is understood to encourage the development of an individual isotope signature within each compartment of a reservoir. Advantageously, stable carbon isotope data are not sensitive to variations in sampling conditions which can occur as a result of pressure or temperature changes during sampling. 30 The fluid samples are obtained using fluid sampling techniques known in the art, and in particular fluid sampling methods which minimize the inclusion of atmospheric air (which -8 contains a small proportion of carbon dioxide). One suitable method of fluid sampling is the use of a down-hole tool including one or more sampling chambers. Using such a tool, the fluid sampled is brought to the surface as a single phase liquid or gas, which is then separated (or "flashed") into gaseous and liquid components in a laboratory. Often, limited sample 5 numbers are collected because of the high operational cost of rig time in an offshore environment. Another suitable method is to conduct surface sampling during a well test, such as a drill stem test (DST) or a production test (PT). When this method is used to collect a fluid sample for a .0 new discovery or appraisal well, the fluid sample is caused to flow up the well bore to the surface where it is separated into different phases (gas, oil or condensate and water) using a wellhead test separator. When a fluid sample is to be collected from a producing field, a full sized production separator, which has one or more sampling ports can be used to collect the fluid sample as required. With this system it is generally possible to take a gas phase sample .5 directly. It is also possible to take single phase samples at the wellhead, which are then separated into liquids and gaseous components in the lab. Another way to obtain fluid samples is by collecting "canned cuttings." Rock samples ("cuttings"), representative of a subsurface formation, are pulverized by a drill bit as the bit 0 penetrates rock strata. The cuttings are collected/suspended in the mud stream that is continuously pumped down the centre of the drill pipe, out through holes in the drill bit, and up the annulus (the gap between the drill string and side of the borehole) during drilling (to help lubricate and cool the drill bit and remove freshly pulverized rock material from around the drill bit). The rock samples are then collected in sealed cans upon return to the surface in 25 the circulating mud stream where the cuttings are able to "degas." Gases accumulating in the sealed cans can then be analyzed in a laboratory as "head space gases." Yet another way of collecting a fluid sample is by directly sampling of gases entrained in the mud system during drilling. As a well drill bit penetrates and pulverizes rock material in its 30 path, free and absorbed gases entrained in the pulverized rock and immediately adjacent rock formation (side of the borehole) are adsorbed by the mud stream as it circulates through the drill bit. These gases are carried to the surface in the returning mud stream and are collected as -9 they exsolve/degas. The present invention has significant value in predicting compartmentalization in offshore gas fields, particularly in situations where traditional reservoir geochemistry does not work. This 5 in turn leads to better development decisions and field development plans (i.e. number of wells and well locations). As such, it can have potential value on the order of tens to hundreds of millions of dollars. Other future benefits could potentially include using the invention to better understand production allocation in a producing field. 10 Now that several embodiments of the invention have been described in detail, it will be apparent to persons skilled in the relevant art that numerous variations and modifications can be made without departing from the basic inventive concepts. For example, it is equally possible to perform the method of the present invention using the stable isotope ratio of oxygen present in fluid samples instead of the stable isotope ratio of carbon dioxide. The 15 stable isotope ratio of oxygen is expressed as "dl80" or "delta-180" which is the difference between the 0-18 composition of a sample relative to the 0-18 composition of an international standard oxygen isotope reference (Vienna Standard Mean Ocean Water or "VSMOW")). The delta-180 isotope ratio from carbon dioxide may be used in a similar way to delta-I 3C to predict compartmentalization. Without wishing to be bound by theory, one of 20 the advantages of oxygen isotopes is that they exchange very rapidly with water. As a result, the oxygen istopes in different compartments that have different volumes of aquifer attached to them, will have different isotope ratios (delta-i 80). When obtaining the fluid samples, care should be taken to ensure that the sample is free of condensed water. This provides a mechanism for oxygen isotopes to be a tool to differentiate different compartments. All such 25 modifications and variations are considered to be within the scope of the present invention, the nature of which is to be determined from the foregoing description and the appended claims. It will be clearly understood that, although a number of prior art publications are referred to 30 herein, this reference does not constitute an admission that any of these documents forms part of the common general knowledge in the art, in Australia or in any other country. In the summary of the invention, the description and claims which follow, except where the context -10 requires otherwise due to express language or necessary implication, the word "comprise" or variations such as "comprises" or "comprising" is used in an inclusive sense, i.e. to specify the presence of the stated features but not to preclude the presence or addition of further features in various embodiments of the invention. 5 EDITORIAL NOTE APPLICATION NUMBER - 2008201132 The following claim page is numbered 12

Claims

1. A method of identifying compartmentalization of a reservoir comprising the step of: a) obtaining a plurality of fluid samples of a reservoir, the plurality of fluid 5 samples taken from a plurality of locations in the reservoir; b) analyzing the plurality of fluid samples to obtain a plurality of compositional data points, each compositional data point providing a representation of the concentration of carbon dioxide present in a given fluid sample; c) analyzing the plurality of fluid samples to obtain a plurality of isotopic data 10 points, each isotopic data point provides a representation of the stable isotope ratio of carbon dioxide or oxygen present in a given fluid sample; d) plotting the plurality of compositional data points against the plurality of isotopic data points for each of the plurality of locations; and, e) analyzing the proximity of the plotted plurality of compositional and isotopic 15 data points as an indication of the degree of compartmentalization of the reservoir.

2. The method of claim I wherein step a) comprises the step of obtain one or more fluid samples from a plurality of locations in the reservoir. 20

3. The method of claim 2 wherein the plurality of locations in the reservoir is a plurality of appraisal wells.

4. The method of claim 3 wherein the plurality of fluid samples is obtained from a plurality of depths within each appraisal well. 25

5. The method of any one of claims 1 to 4 further comprising the step of recording the pressure and temperature conditions of the reservoir during the step of obtaining the plurality of fluid samples so that the compositional data points can be normalized as a function of reservoir conditions. 30

6. The method any one of claims 1 to 5 wherein steps b) and c) are repeated to generate error bars indicative of a level of analytical precision and the error bars are assigned to each compositional or isotopic data point. - 13

7. The method of any one of claims I to 6 wherein step a) comprises fluid sampling using a down-hole tool including one or more sampling chambers. 5

8. The method of any one of claims 1 to 6 wherein step a) comprises surface sampling of fluid from a producing field.

9. The method of any one of claims 1 to 6 wherein step a) comprises the step of collecting canned cuttings and steps b) and c) are conducted by analyzing the head space gas 10 which exsolves from the canned cuttings.

10. The method of any one of claims I to 6 wherein step a) comprises the step of direct sampling of gases entrained in drilling mud. 15

11. The method of any one of claims I to 10 wherein the reservoir is a hydrocarbon reservoir.

12. A method of identifying compartmentalization of a reservoir substantially as herein described. 20