GB2417739A

GB2417739A - Method of enhancing oil recovery

Info

Publication number: GB2417739A
Application number: GB0419405A
Authority: GB
Inventors: Bjoern Berger; Ola Eiken
Original assignee: Statoil ASA
Current assignee: Equinor ASA
Priority date: 2004-09-01
Filing date: 2004-09-01
Publication date: 2006-03-08
Anticipated expiration: 2024-09-01
Also published as: NO20054046L; NO336774B1; GB2417739B; NO20054046D0; GB0419405D0

Abstract

The present invention provides a method of enhancing oil recovery from a sub-surface oil reservoir having present therein a first producer well and an injector well, said method comprising: injecting carbon dioxide down said injector well before the end of the primary phase of reservoir life; allowing injected carbon dioxide to penetrate into an oil bearing stratum of the formation surrounding said injector well; generating a three-dimensional seismographic image of at least a portion of said reservoir into which injected carbon dioxide has penetrated; identifying from said image regions of formation with abnormal permeability to fluid flow; at least in part using that identification, constructing a computer model of fluid flow within the reservoir; using said model to predict the effects of at least one of the following actions (i) placing a further producer well in said reservoir, (ii) placing a further injector well in said reservoir, (iii) altering the hydrocarbon extraction rate from an existing producer well in said reservoir, and (iv) altering the flow rate of or nature of injectant at an existing injector well in said reservoir; and taking at least one of the said actions.

Description

24 1 7739 - 1 Method This invention relates to improvements in and

relating to methods of oil field management, in particular to such methods involving the use of contrast enhanced seismic imaging of sub- surface formations to enhance oil recovery from sub-surface oil reservoirs, and especially to the use of carbon dioxide as the contrast agent in such methods.

Seismic surveys are routinely used in oil and gas exploration. Such surveys can be used to generate a three-dimensional image of the subsurface formation.

Such images may be used to increase the chances of successfully locating oil or gas using exploration wells, and to provide data for fluid flow simulation models of the sub-surface reservoirs that are identified. Moreover by repeating the survey at time intervals, i.e. using fourdimensional or time-lapse 3D seismic imaging, it is possible to detect changes in a sub-surface hydrocarbon reservoir. This is important as such changes can be used to identify gas or oil pockets of a size sufficient to justify drilling a further producer well. See for example Jack, "TimeLapse Seismic in Reservoir Management", First Annual Distinguished Instructor Short Course, 1998, Society of Exploration Geophysicists, Tulsa, USA.

Once a sub-surface hydrocarbon reservoir has been found and oil and/or gas extraction has begun, it is important to optimize the extraction process. This will generally involve drilling further producer wells (i.e. wells from which hydrocarbons are extracted) and, as the reservoir pressure begins to fall, injection wells (i.e. wells down which water or methane is injected into the reservoir to drive oil or gas towards the producer wells). In the end stage of the reservoir life it has become a practice to inject carbon dioxide to prolong reservoir life a bit and to avoid release of the carbon dioxide into the atmosphere. Thus reservoir life is conventionally split into three phases, primary, secondary (where water or methane injection is required) and tertiary or final.

In the primary and secondary phases of reservoir life, injection of carbon dioxide is thought to be undesirable because of the extra expense it involves and because carbon dioxide entrained in the hydrocarbon flow from the producer wells is a contaminant that has to be removed, resulting in further expense.

It is known that it is possible, using cross-well- seismic profiling, to detect the fact that carbon dioxide has been injected into a sub-surface reservoir.

See for example Harris et al, 66th Annual Seg. Int Mtg (Denver, Wed. pm 13 Nov. 1996) pages 1870-1872.

The present inventors have now realised however that carbon dioxide may be injected sub-surface before or during the primary phase of reservoir life in order to act as a contrast agent in seismographic imaging and so improve reservoir flow simulations and hence improve reservoir management even at the earlier stages of reservoir life.

Contrast agents are used in medical diagnostic imaging procedures so as to enhance the differences in imaging signal strength between different body tissues, i.e. to increase the contrast between such tissues in the image that is generated and so allow the physician to see more clearly the tissues of interest or abnormalities within such tissues. Typically in X-ray imaging the contrast agents used are more X-ray opaque than flesh or blood - 3 while in magnetic resonance imaging the contrast agents used typically serve to shorten the relaxation times of the protons in adjacent water molecules and so increase or decrease the strength of the magnetic resonance signal from those protons.

The present inventors have now found that carbon dioxide injected subsurface can similarly be used to enhance contrast in seismographic imaging and particularly in 4D seismographic imaging as a result of the higher tendency of carbon dioxide (relative to oil or methane) to remain in the oil bearing strata.

More particularly use of carbon dioxide as a contrast agent in seismographic imaging enables the detection of regions of the formation in which fluid (e.g. carbon dioxide, oil, gas or water) flow is enhanced or reduced, e.g. due to the presence of reduced permeability strata (for example shale strata), faults, or "chimneys" of increased permeability matrix. Since it is carbon dioxide flow and build-up that enables these regions to be identified, it is highly preferable to use 4D- seismographic imaging in the methods of the invention as differences between images of the same 3D space, taken at two or more different times (when at least one such image includes injected carbon dioxide as a contrast agent), will highlight the regions of low or high permeability that are of interest. While simple visual comparison may be used, it will more generally be the case that images will be overlaid or subtracted in order to highlight regions of change. Particularly desirably such regions of change will then be superimposed on a "native" image, i.e. one in which there is no contrast agent used, of the same 3D-space. Such subtraction and superposition techniques are conventional in 4D- seismography.

With such regions identified, it is then possible to improve reservoir management, e.g. by placing new producer or injector wells (e.g. socalled in-fill wells), by altering hydrocarbon withdrawal rates from one or more existing producer wells, by altering injection rates in one or more existing injector wells so as to alter the rate or direction in which hydrocarbon in the reservoir is driven, and by changing the material injected so as to alter fluid viscosity and/or matrix permeability (e.g. injecting foam to reduce matrix permeability in break through zones).

Conventionally, such strategies of reservoir management have been seen to be particularly important in the mid to late life of a reservoir in order to optimize hydrocarbon recovery and prolong reservoir life or to facilitate the decision to bring production to an end.

However the present inventors have realised that with early carbon dioxide injection and seismographic imaging, the earlier than conventional implementation of such management strategies can further increase hydrocarbon recovery, prolong reservoir life, and reduce drilling expenses.

Thus with an improved reservoir flow model at an early stage of reservoir life it is possible to reduce the number of in-fill wells that are required to drain the reservoir efficiently. While in-fill wells are always expensive, they are significantly more so with off-shore reservoirs, especially deep water reservoirs, and thus the present invention is of particular relevance to off shore reservoirs.

Thus viewed from one aspect the invention provides a method of enhancing oil recovery from a sub-surface oil reservoir having present therein a first producer well and an injector well, said method comprising: injecting carbon dioxide down said injector well before the end of - 5 the primary phase of reservoir life; allowing injected carbon dioxide to penetrate into an oil bearing stratum of the formation surrounding said injector well; generating a three-dimensional seismographic image of at least a portion of said reservoir into which injected carbon dioxide has penetrated; identifying from said image regions of formation with abnormal permeability to fluid flow; at least in part using that identification, constructing a computer model of fluid flow within the reservoir; using said model to predict the effects of at least one of the following actions (i) placing a further producer well in said reservoir, (ii) placing a further injector well in said reservoir, (iii) altering the hydrocarbon extraction rate from an existing producer well in said reservoir, and (iv) altering the flow rate of or nature of injectant at an existing injector well in said reservoir; and taking at least one of the said actions.

Computer modelling of fluid flow in sub-surface oil reservoirs is a conventional technique and may be performed in conventional fashion in the operation of the method of the invention. However, in the generation of a reservoir model, it is recommended that the temperatures and pressures recorded down hole be factored in in order that the fluid properties of the injected CO2 may be modelled as accurately as possible since the local CO2 density is particularly dependent on these properties.

Simulation may be effected using simulators such as Simed II and Eclipse 100.

Simed II is a multi-component reservoir simulator which initially was designed for modelling the drainage of methane from coal seams. The simulator includes a gas phase density calculation using a Peng-Robinson equation - 6 of state with a Chien-Monroy correction, and viscosity by the Jossi-Thiel-Thodos method. For present purposes, the simulator may be implemented with an option to specify depth-related temperatures for each grid block thus preserving a consistent density versus depth profile.

Eclipse 100 is a black-oil simulator that can handle up to four flowing phases. Only the oil and gas phases need to be used for present purposes. The oil phase is given pVT and phase data corresponding to brine and the gas phase is given properties corresponding to CO2. This allows both solubility properties and density versus depth data to be consistently represented as the pressure variation in the model is dominated by the hydrostatic pressure gradient throughout the simulation.

CO2 densities for the pVT table may be calculated by the EOS developed by Span and Wagner (1996), (http://wwwesd.lbl.gov/GEOSEQ/code/testprob_7.html).

Seismographic imaging of sub-surface oil reservoirs is also a conventional technique and may be performed in conventional fashion in the operation of the method of the invention. Preferably however the method of the invention will use fixed receivers and elastic wave generators so that CO2 enhanced seismographic images may be generated repeatedly in order that the fluid flow simulation model may be updated regularly.

While carbon dioxide injection is required before or during the primary phase of reservoir life, it may be continued or repeated in the secondary and/or tertiary phases.

Where this text refers to placement of new wells this should be understood to include the creation of new injection or recovery sites in existing wells and the creation of branches off existing wells.

Where reduced permeability strata are identified it is of course of particular interest to place fresh in-fill producer wells in zones within the matrix in which oil flow to existing producer wells is hindered by these strata.

By abnormal or abnormally high or low is meant herein that the content of carbon dioxide within one zone is sufficiently higher or lower than that in an adjacent (e.g. vertically or horizontally adjacent) zone in the formation that the reflected sound intensity from the two zones is statistically significantly different, i.e. that the contrast enhanced image shows a detectable dimming or brightening that can be attributed to the presence of the contrast agent.

Quite surprisingly, the capability of the seismographic imaging technique to show structural features is significantly improved by the use of carbon dioxide as a contrast agent.

Almost invariably, the step of identifying regions of abnormal permeability in the methods of the invention will involve comparison with an earlier 3D-seismographic image of the reservoir. In such a case, the method comprises a method of 4D-seismography. However where a contrast enhanced 3D image shows (as a result of contrast enhancement) well defined structures, the 3D image alone may be sufficient to identify regions of abnormal permeability.

Three dimensional seismography technique, as used in the method of the invention, is a well-known technique, described for example by Sheriff et al. "Exploration - 8 Seismography", 2nd Edition, Cambridge University Press, 1995. The technique generally involves placing down or towing an array of receivers (e.g. hydrophores or geophones for example in rows), and a set of elastic wave generators (e.g. vibrators, airguns or explosives) for example along a line parallel or orthoganol to rows of receivers. The elastic wave generators are simultaneously triggered and the waves reflected by the sub-surface formation are detected (for example in terms of time-series of pressure, particle velocity or acceleration or displacement) by the receivers and stored for computer manipulation. If desired the array of receivers and wave generators may then be moved and the exercise may be repeated. The information collected is then processed by computer to generate a three- dimensional image of the surveyed portion of the sub- surface formation. This image may be presented to the user in many different ways, e.g. as a two or three dimensional image of a selected plane through or volume of the surveyed area, etc. When two or more three dimensional images of the surveyed area taken at different times (usually different years, e.g. one to ten years apart), these may be compared by eye or using a computer to determine zones in which the image has changed with time, e.g. due to the arrival of a contrast agent or the depletion of oil or gas content. Again this comparison may be presented to the user in many ways, e.g. a difference image imposed on a native image, or a two or three dimensional map of the changes identified, etc., preferably also providing the locations of producer and/or injector wells and, if relevant, surface obstructions, etc. The seismographic data is then used in a computer simulation of fluid flow within the formation so as to predict the effects on hydrocarbon recovery of placing new producer or injection wells and/or of changing injection or recovery rates at existing wells. In this way the seismographic - 9 information may be used as the basis for new well placement or injection or recovery changes.

In general the construction of the fluid flow simulation model will involve constructing a seismic model, adjusting the constructed seismic model to match the observed seismic data, and coupling the adjusted seismic model to a fluid flow model. The resulting fluid flow model may then be run to simulate the effects of placement of new injector or producer wells, altering flow rates to or from injector or producer wells, etc. In this way optimal well placement and injection/ extraction rates may be determined.

The contrast agent injection may be effected in essentially the same manner as that in which injection is conventionally effected in order to increase hydrocarbon recovery. At the point of injection, the carbon dioxide is generally in a supercritical state and it has been found that the seismic detectability of supercritical carbon dioxide is excellent. Desirably the carbon dioxide is injected in substantially pure form, e.g. at least 50% mole CO2, preferably at least 90% mole CO2, more preferably at least 95% mole CO2. Other gases, for example steam, C13 hydrocarbons, nitrogen, etc. may be present in the injected contrast agent.

Carbon dioxide injection in the method of the invention is preferably begun before the end of a year from primary phase production beginning, especially preferably before rim extraction is commenced.

Particularly preferably it is begun before more than 10 producer wells are in place.

The quantity of carbon dioxide injected will generally be in the range 0. 5 to 10 million tonnes per annum.

The carbon dioxide injection may be effected continuously whereby the injected carbon dioxide will also serve to maintain down hole pressure and increase hydrocarbon recovery. However, if desired, carbon dioxide injection may be on a "one-off" or an occasional basis with, if desired, other injectants such as water or methane being used at other times.

The carbon dioxide injection may take place at two or more injector wells in the survey area and the survey area may include two or more producer wells. What is important is that by identifying regions of abnormal permeability to carbon dioxide, the field operator is enabled to select effective locations at which to site new producer wells and so increase the hydrocarbon

recovery from the field.

Seismographic imaging in the method of the invention is preferably effected at least six months after carbon dioxide injection has commenced in order to allow dispersion of the carbon dioxide through a significant volume of the oil-bearing stratum.

The benefits of the methods of the invention in terms of improving the characterization of the formation in a hydrocarbon reservoir are such that it may be desirable to use carbon dioxide injection in place of water or methane injections, where these currently take place, to increase hydrocarbon recovery and it may also be desirable to begin carbon dioxide injection at earlier stages of a reservoir life. Both of these measures also provide the opportunity for carbon dioxide disposal thus assisting efforts to combat worsening of the greenhouse effect.

The method of the invention is especially applicable to off-shore oil reservoirs.

Claims

Claims 1. A method of enhancing oil recovery from a sub- surface oil

reservoir having present therein a first producer well and an injector well, said method comprising: injecting carbon dioxide down said injector well before the end of the primary phase of reservoir life; allowing injected carbon dioxide to penetrate into an oil bearing stratum of the formation surrounding said injector well; generating a three- dimensional seismographic image of at least a portion of said reservoir into which injected carbon dioxide has penetrated; identifying from said image regions of formation with abnormal permeability to fluid flow; at least in part using that identification, constructing a computer model of fluid flow within the reservoir; using said model to predict the effects of at least one of the following actions (i) placing a further producer well in said reservoir, (ii) placing a further injector well in said reservoir, (iii) altering the hydrocarbon extraction rate from an existing producer well in said reservoir, and (iv) altering the flow rate of or nature of injectant at an existing injector well in said reservoir; and taking at least one of the said actions.

Amendments to the claims have been filed as follows 1. A method of enhancing oil recovery from a sub- surface oil reservoir having present therein a first producer well and an injector well, said method comprising: injecting carbon dioxide down said injector well before the end of the primary phase of reservoir life; allowing injected carbon dioxide to penetrate into an oil bearing stratum of the formation surrounding said injector well; generating a three- dimensional seismographic image of at least a portion of said reservoir into which injected carbon dioxide has penetrated; identifying from said image regions of formation with abnormal permeability to fluid flow; at least in part using that identification, constructing a computer model of fluid flow within the reservoir; using ace;'. said model to predict the effects of at least one of the ë following actions (i) placing a further producer well in said reservoir, (ii) placing a further injector well in said reservoir, (iii) altering the hydrocarbon extraction rate from an existing producer well in said reservoir, and (iv) altering the flow rate of or nature of injectant at an existing injector well in said reservoir; and taking at least one of the said actions.
2. A method as claimed in claim 1 wherein said three dimensional seismographic image is generated using fixed receivers and elastic wave generators so that CO2 enhanced seismographic images may be generated repeatedly in order that the fluid flow simulation model may be updated regularly.
3. A method as claimed in claim 1 or claim 2 wherein carbon dioxide injection is continued or repeated in the secondary and/or tertiary phases.
4. A method as claimed in any one of the preceding - 13 claims wherein at the point of injection the carbon dioxide is in a supercritical state.
5. A method as claimed in any one of the preceding claims wherein the injected carbon dioxide is at least 50% mole CO2.
6. A method as claimed in any one of the preceding claims wherein the injected carbon dioxide is at least mole CO2.
7. A method as claimed in any one of the preceding claims wherein carbon dioxide injection is begun before rim extraction is commenced. I@ me <e @ .C.. Be@ @ *...