US3282095A

US3282095A - Logging oil saturation in reservoir

Info

Publication number: US3282095A
Application number: US306276A
Authority: US
Inventors: William W Owens
Original assignee: Pan American Petroleum Corp
Current assignee: Pan American Petroleum Corp
Priority date: 1963-09-03
Filing date: 1963-09-03
Publication date: 1966-11-01
Anticipated expiration: 1983-11-01

Description

3282,95 Patented Nov. 1, 1966 3,Z82.,tt5 LQGGING 01L dATURATlON EN RESERVULR Wiiiiarn W. Owens, Tulsa, ida., assignor to Pan American Petroleum Corporation, Tulsa, Okla, a corporation of Delaware No Dre. 'ing. Filed Sept. 3, 1963, Ser. No. 306,276 '7 Ciaims. (Cl. 73-151) This invention relates to the determination of the relative amounts of oil (more properly, oil saturation) in a reservoir in which there is some pore space filled by gas. Accordingly, this invention has particular applicability to measuring the oil saturation in partially or totally depleted subsurface reservoirs.

There are no reliable methods now available for determining residual oil saturation in partially depleted reservoirs. It has been proposed to use ordinary cores or sidewall cores for this purpose. However, the fluid saturation of such coresand, in fact, of any coresis altered by imbibition or forceable entry of oil or water as well as by partial depletion due to the presence of gas. Thus, oil could be imbibed by a core if oil is used in coring operationseither crude oil from the formation, or the oil in oil base mud. Water used in drilling fluids in various types of core drilling may be imbibed or forced into the formation during coring. Gas dissolved in the liquid content of the core will evolve from solution as the core is pulled from the well, driving liquids out of the core. Quantitatively, the degree of error introduced in core measurements due to flushing of the core by the drilling fluid varies, depending upon the fluid used, and the conditions in the reservoir. There are occasions when the oil saturation (i.e., fractional part or percent of the pore volume occupied by oil) can be assumed to be substantially correct, particularly when the oil saturation is so low that there is little permeability to that phase, but this is rarely the case.

The problem of measuring oil saturation in a partly depleted reservoir is complicated by the movement of the reservoir fluids (roughly classified as gas, oil, and formation Water, the latter term referring to the water or brine indigenous to the formation) as a result of the normal depletion processes, gravity drainage, regional migration, etc., and additionally, as a result of invasion of drilling fluid or drilling fluid filtrate.

Accordingly, it is an object of this invention to determine the oil saturation of subsurface porous zones where such zones are partially depleted of their initial liquid content. This object is accomplished by carrying out a number of measurements of physical properties in the well in a definite sequence. More specifically, it is the employment of certain types of well logging procedures in predetermined sequence and approximately at the same time, together with mathematical calculation. As a result, it is possible to determine with reasonably good accuracy the gas saturation, the water saturation, and the oil saturation of these subsurface rocks.

Another object of this invention is to determine the oil saturation in a subsurface oil-producing reservoir under steady-state conditions; that is, such that the oil, gas and formation water saturation in the Zone of investigation adjacent the bore of the well is substantially that prevailing in the formation at a considerable radial distance from the bore.

Essentially, the method steps involve an initial conditioning of the well to produce as near as can be the same gas, oil, and Water saturation adjacent the bore as that present in the formation remote from the well. In some cases, as discussed below, this step may be unnecessary. The next step consists in making a core analysis for water saturation or making at least one electric log (and possibly one or more surface determinations) from which the water saturation of the reservoir formations of interest can be computed. Following this a neutron-gamma ray log is made. This produces, as is well known in the art, an indication from which can be computed the total liquid content of the formations. Following this, a hydrogencontaining liquid is injected into the well in sufficient quantity to displace or take into solution the entire gas phase present adjacent the bore of the well to a depth beyond that of the depth of penetration of the neutrongamma ray survey. Immediately following this, a second neutron-gamma ray log of the same (now flooded) formations is made. From the difference in these last two logs, a determination of the gas saturation of the formations that have been logged can be made. The second neutron-gamma ray log by itself permits determination of the total porosity of each formation. The total liquid content (from the first neutron-gamma ray log) divided by total porosity gives the sum of water and oil saturations. Since the oil and water saturation has been determined and the water saturation separately measured by the electrical log (or by core analysis), it is possible to compute the oil saturation by difference.

All well logging techniques currently known measure physical properties of the formations and their fluid contents immediately adjacent the bore. There is some variation in effective depth of penetration, but at best this is only a few feet. On the other hand, it is Well known to reservoir engineers that the relative content of gas, oil and formation water a considerable distance from the bore is frequently quite different from that near the bore. For example, in a partly depleted reservoir, the setting of the well pump intake considerably above a particular formation means that the fluid level will be considerably higher than it is back in the formation. Rapid production of fluid from a formation may result in the phenomenon of water-coming thus producing a higher water saturation adjacent the bore than that deep in the formation. If a new well is drilled into a partly depleted formation, or if coring is carried out in an old Well, the presence of the drilling fluid may introduce changes in saturations at the bore compared to back in the formation. Thus, for example, if water or oil base mud is used in the drilling or coring, the filtrate will produce an abnormal amount of water or oil, depending on the nature of the filtrate, which is considerably different from the steady-state condition back in the formation. Due to all such effects, it is desirable before the logging procedure to restore each formation as nearly as possible to the steady-state conditions.

One satisfactory initial step in such partly depleted reservoirs, if economics do not rule it out, is to drill a new well into a reservoir using gas under pressure (natural gas, compressed air, or the like) as the drilling fluid. Where this procedure is possible, I have found by experience that there is relatively insignificant changing of the conditions prevalent in the reservoir before the well is drilled to those existing when the drilling is stopped. Certainly, the type of gas present in the partly depleted Zones may be of a different nature, but the liquid saturations are usually very little affected. However, it is not always possible to drill this new well. If an old well must be used, the initial procedural step should involve producing the well with the pump intake as low as possible for a substantial period of time, which should be at least a half day, and preferably from one to several days. This permits the liqiuds present in the reservoir immediately adjacent the bore to be drained approximately to the saturations prevailing a considerable distance in the reservoir and, accordingly, the relative fluid contents of the reservoir rocks adjacent the well approach the steadystate condition prevailing in most of the reservoir. Of course, if the well has already been producing for a considerable period of time under the conditions outlined above, there is no need for such an initial step before proceeding with the Well logging.

The next step following the conditioning of the well involvcs measuring the formation water saturation in the rocks adjacent the well. I prefer to use analysis of cores cut with oil-filtrate drilling fluid, since this method is the most reliable known. However, it may not be economically feasible or even possible to obtain such cores. Sever-a1 well-logging procedures have been devised which permit such measurement to be made. If a logging technique is to be used, I prefer to use the indication logging technique, in which an alternating electromagnetic field is produced by the logging instrument and the reaction of this field with the formation water in the rocks adjacent the well bore produces a surface indication primarily responsive to the resistivity of this formation water. This technique measures the so-called true resistivity R, of the rock and its water content. The formation water saturation is usually determined from this true resistivity R using the Archie empirical formula P (SW) it where S is the desired water saturation,

n is an exponent conventionally considered for water- Wet formations to lie within the limits of 1.8 to 2.1, and

R is the resistivity of the rock saturated completely with the formation water.

It is seen that in order to determine the water saturation it is essential that the computer know the value for R This may, for example, be determined by taking a sample of formation water, saturating a core of the formation rock with it, and directly determining the resistivity of the saturated rock, which will be R Another procedure which is frequently used is to determine or estimate the resistivity formation factor F (discussed in detail in Handbook of Well Log Analysis, by Sylvain J. Pirson, Prentice-Hall, Inc., 1963, pp. 22-24) since by definition R =FR where R is the resistivity of the formation water. Thus, if a core is not available for a particular formation, but the value of the formation factor F is known, it is sufficient to measure the resistivity of the formation water produced from the formation of interest in order to determine R for substitution in the Archie formula. Formation water resistivity R may be directly measured at the surface by well-known electrical measurements on samples of formation water collected from the various formations in the well. In the absence of such samples, this resistivity may be computed by running a spontaneous potential log and following the procedures set forth, for example, in the above-mentioned book, pp. 66 and 7576.

The particular advantage of using the induction method for the electrical resistivity log of the formations is dual. First, when using this method there is no need to introduce an electrically conducting liquid in the bore to insure good electrode contact from the well logging tool to the formation (which is an advantage, since the presence of such conductive liquid contaminates to a degree the formation adjacent the bore). Secondly, the induction logging tool is chiefly responsive to the resistivity of the formation water a considerable radial distance from the well, but over a relatively narrow vertical distance. Thus, if a plurality of thin formations is encountered, this type of log offers a good possibility of obtaining more definitive results than when using the single or multielectrode well logging techniques. However, if induction logging equipment is not immediately available, a single or multiple electrode electrical resistivity log may be madeto determine R,. In this case care should be taken to use a relatively wide electrode separation (of the order of 4 to 6 feet or more, using a point-electrode focused-current configuration, as described in the above book, pp. 145-150), so that this log is chiefly responsive to the resistivity of the water-filled portions of the rocks beyond the invaded zone in the well. The invaded zone is that portion of the rock adjacent the bore which has been penetrated by filtrate from the conductive liquid in the well itself.

After the data have been obtained from which the formation water saturation can be determined for the plurality of adjacent rocks bounding the well, the next step is to make a neutron-gamma ray log of this same subsurface region. See, for example, the Albertson U.S. Patent 2,352,993. Such logs have been used for a number of years very satisfactorily. The log obtained in such a procedure is directly related to gamma radiation reaching a detector such as a scintillometer, a Geiger counter, ionization gauge or the like, measured in terms of depth. The gamma radiation, in turn, is largely due to the capture by hydrogen atoms of thermal neutrons emitted from a neutron source present in the logging tool, but separated a considerable distance from the detector (around two to six feet). Accordingly, the output or log is directly related to the hydrogen content of the neutron-irradiated part of the formations surrounding the well. Such logging devices respond to the amount of hydrogen-containing liquid in the rocks, since nearly all rocks have negligible concentration of hydrogen in their chemical composition. By hydrogen-containing liquid, I mean a hydrocarbon or water or the like. In practice it is found that the re sultant log from such neutron-gamma ray equipment essentially is correlatable with the liquid content of the porous rocks; i.e., the volume of the oil and formation water in the volume of neutron-irradiated rock. As a result, this first neutron-gamma ray log measures the combined oil and formation water content while the formations adjacent the bore being logged still contain their normal or steady-state gas saturation.

It is important to remember that the effective penetration of the neutron-gamma ray log is at most of the order of one to two feet radially outward from the bore of the well. It is readily apparent that one can reduce the gas saturation of a partly depleted reservoir rock substantially to zero, insofar as the neutron-gamma ray log is concerned, by flooding the well with a hydrogen-containing liquid until the rocks adjacent the bore are substantially percent liquid-filled to a radial distance greater than about two feet. When the expression to flood rocks is used, it is to be understood that this simply means filling the pore space of the rocks to a radial distance from the bore greater than the effective penetration depth of the neutron-gamma ray logging equipment used, with a hydrogen-containing liquid. If the fluid level in the well is maintained above all zones to be logged, for the order of an hour to a few hours at most, it will ordi-, narily be found that all adjacent rocks have been flooded. A rough rule of thumb is to inject 10 barrels of hydrogencontaining liquid per foot of exposed formation. It is always possible to check the flooding by making two more neutron-gamma ray logs in the well, separated in time. If both logs show substantially the same output at the same depth, it may be assumed that flooding was complete. As a factor of experience, I find that, ordinarily, only one additional neutron-gamma ray log need be made (i. e., the second such log of the total procedure) after maintaining the liquid level of the well above the top of the highest formation to be logged until the desired volume of liquid has been injected.

This second neutron-gamma ray log can be calibrated, as is well known in the art, to give the values of total liquid volume in the formations adjacent the well bore. In other words, this is a measurement of the total porosity of the formations.

The first neutron-gamma ray log measured total liquid content before the gas space was eliminated. The second measured total porosity of the same rocks. The ratio of the two measurements is directly proportional to the sum of oil plus water saturation of the formations that were logged. The Water saturation of these same formations has already been determined from the resistivity log through the use of the Archie formula or by core analysis.

It is now possible, therefore, to compute the difference between oil and water saturation and that due to water, which gives the desired oil saturation.

One could use crude oil instead of water for flooding the rocks around the Well bore, but ordinarily it is more economical to use water.

As an example of this procedure, a well was drilled in a partly depleted oil reservoir in Wyoming. This well was drilled to a depth of approximately 1240 feet and casing set at that elevation. The well was then drilled with gas to a depth of 1413 feet, at which point the partly depleted oil formation was encountered. The formation below this point was then cored, again using gas as the drilling fluid to a depth of 1543 feet. Highest fluid level measured was 1523 feet.

The well was allowed to produce. While it was producing, an induction log was run in the well, followed by a natural gamma ray log and a neutron-gamma ray log. After these initial logs were obtained, water was injected into the well to take into solution or displace the gas saturation in the formations immediately surrounding the well. The injection rate was approximately 3,000 barrels per day. After injection for 50 minutes, a gamma ray and a neutron-gamma ray log were run through the uncased portion of the well. As a check, a third neutrongamma ray log was run after water had been injected for three hours and 50 minutes. The fluid level during the injection period was near the surface.

It was assumed that the liquid content of the cores from this well was little affected by the drilling and coring procedure, and accordingly, it was assumed that the water and oil saturations obtained were substantially those prevailing in the formation. It was found that in the range of 1450 feet to 1520 feet (Well depth) water saturation based on core analysis varied in the range of to 40 percent and the majority of oil saturations in the range of 20 to about 40 percent. Corresponding values for oil saturation using the logging technique considered here Were quite close, similar values ranging from 20 to about 40 percent maximum. Corresponding values for water saturation averaged a few percent higher than from the core analysis results, but the general trends were quite similar.

It is to be understood that the technique employed has been described generally, because there are various changes in details which each log analyst chooses to employ which may slightly modify the results. Accordingly, this invention is best described by the appended claims.

I claim:

1. A method of measuring oil saturation of subsurface porous zones including the steps of (1) measuring the formation water saturation of a plurality of adjacent rocks bounding a well,

(2) radiating said rocks with neutrons and producing a surface indication related to the resultant gamma radiation due to neutron radiation as a function of depth in said well whereby the total liquid content may be determined,

(3) injecting a hydrogen-containing liquid into said Well in sufiicient volume substantially to flood said plurality of adjacent rocks bounding said well, and

(4) repeating step (2) above while said plurality of rocks is flooded with said liquid whereby the total porosity may be determined, the above-mentioned steps thereby permitting the calculation of the oil saturation by determining the sum of the oil plus formation water saturation as the ratio of the total liquid content to the total porosity, and by subtracting therefrom the previously determined formation water saturation.

2. A method of measuring oil saturation of subsurface porous zones including the steps of (1) making an electrical resistivity log in a plurality of adjacent rocks bounding a Well whereby the formation Water saturation may be determined,

(3) injecting a hydrogen-containing liquid into said well in sufficient volume substantially to flood said plurality of adjacent rocks bounding said well, and

3. A method of measuring oil saturation of subsurface porous zones including the steps of (1) making an electrical resistivity log in a plurality of adjacent rocks bounding a well,

(2) measuring the electrical resistivity of the formation water produced from said rocks bounding said well whereby the formation Water saturation may be determined,

(3) radiating said rocks with neutrons and producing a surface indication related to the resultant gamma radiation due to neutron radiation as a function of depth in said well whereby the total liquid content may be determined,

(4) injecting water into said Well in sufiicient volume to flood said rocks bounding said well, and

(5) repeating step (3) above while said rocks are flooded with water whereby the total porosity may be determined, the above-mentioned steps thereby permitting the calculation of the oil saturation by determining the sum of the oil plus formation water saturation as the ratio of the total liquid content to the total porosity, and by subtracting therefrom the previously determined formation water saturation.

4. A method in accordance with claim 3 in which said electrical resistivity log is chiefly responsive to the waterfilled portions of said rocks beyond the invaded zone in said well.

5. A method in accordance with claim 4 in which fluid is produced from said well prior to step (1) for a substantial period of time, during which the relative fluid content of said rocks at least approaches a steady-state condition.

6. A method of measuring oil saturation of subsurface porous Zones including the steps of 1) making an electrical resistivity log in a plurality of adjacent rocks bounding a well,

(2) measuring the electrical resistivity of the formation water by making a spontaneous potential log in said plurality of adjacent rocks whereby the forma tion water saturation may be determined,

(4) injecting water into said well in sufficient volume to flood said rocks bounding said well, and

(5) repeating step (3) above While said rocks are flooded with water whereby the total porosity may be determined, the above-mentioned steps thereby permitting the calculation of the oil saturation by determining the sum of the oil plus water saturation as the ratio of the total liquid content to the total porosity, and by subtracting therefrom the previously determined formation water saturation.

7. A method of determining oil saturation in a subsurface reservoir including the steps of 7 8 (l) drilling a well intosaid reservoir using gas as the I I saturation by determining the sumof the oil plus drilling fluid; the lower portion of said well being un I 2 formation Water saturation as the ratio of the total I cased I I liquid content to the total porosity, and by subtract- (2) measuring the formation Water saturation of a'plu I I I I ing therefrom the previously determined formation I 'rality of adjacent rocks bounding a Well,

, water saturation. (3) radiating said rocks with neutrons and producing I a'surface indication related to the 'resultant'ga'rnma References Cited y t miner I radiation due toneutronradiation as a function of I STATES. PATENTS depth-insaid Well whereby the total liquid content 2172' 625 939 I Schhlmberger 152 X may be determined, 10 (4) injecting a hydrogen-containing liquidinto said g ;:$zg H'-*" i5i?g Well in sufiicient volume substantially to flood said I 3, 8 1/1965. ,Coek 7 I I 'plurality'of adjacent rocks bounding said'we'll; and

(5') repeating step-(3) above While 'said'pluralityof I rocks .is flooded with. said liquid whereby the total 15 RICHARD QUEISSER Puma), Exammer' i porosity may. be determined, the above rnentio'ned I I ACK C, .GOLDS Assistant x min 1 i I I steps thereby permitting the calculation of the oil

Claims

1. A METHOD OF MEASURING OIL SATURATION OF SUBSURFACE POROUS ZONES INCLUDING THE STEPS OF (1) MEASURING THE FORMATION WATER SATURATION OF A PLURALITY OF ADJACENT ROCKS BOUNDING A WELL, (2) RADIATING SAID ROCKS WITH NEUTRONS AND PRODUCING A SURFACE INDICATION RELATED TO THE RESULTANT GAMMA RADIATION DUE TO NEUTTRON RADIATION AS A FUNCTION OF DEPTH IN SAID WELL WHEREBY THE TOTAL LIQUID CONTENT MAY BE DETERMINED, (3) INJECTING A HYDROGEN-CONTAINING LIQUID INTO SAID WELL IN SUFFICIENT VOLUME SUBSTANTIALLY TO FLOOD SAID PLURALITY OF ADJACENT ROCKS BOUNDING SAID WELL, AND (4) REPEATING STEP (2) ABOVE WHILE SAID PLURALITY OF ROCKS IS FLOODED WITH SAID LIQUID WHEREBY THE TOTAL POROSITY MAY BE DETERMINED, THE ABOVE-MENTIONED STEPS THEREBY PERMITTING THE CALCULATION OF THE OIL SATURATION BY DETERMINING THE SUM OF THE OIL PLUS FORMATION WATER SATURATION AS THE RATIO OF THE TOTAL LIQUID CONTENT TO THE TOTAL POROSITY, AND BY SUBTRACTING THEREFROM THE PREVIOUSLY DETERMINED FORMATION WATER SATURATION.