Hydraulic Fracture-Field Test to Determine Areal Extent and Orientation

J. J. REYNOLDS CONTINENTAL OIL CO. MEMBER AIME HOUSTON, TEX, J. B. SCOTT J. l. POPHAM· MEMBER AIME PONCA CITY, OKLA. H. F. COFFER

MEMBER AIME Downloaded from http://onepetro.org/jpt/article-pdf/13/04/371/2238182/spe-1571-g-pa.pdf by guest on 01 October 2021

ABSTRACT to actual field data on fracture properties. No attempt is made to prove that the same type of fracture occurs This paper concerns field experiments to define the in all wells. areal extent, orientation and thickness of an artificial fracture in the Sacatosa field, Maverick County, Tex. The field procedure was to drill 14 test holes at The fracture was made by a sand-oil treatment of 176,- various locations around the fractured well. By em­ 000 gal of lease crude containing a fluid-loss additive ploying several different testing techniques, the presence and 270,000 lb of 20-40 mesh subangular Poteet sand. of the fracture and some of its characteristics were The well was perforated with a jet gun, consisting of determined. These techniques as well as the results six shots in a single plane. obtained are discussed in detail in this paper. Fourteen test holes were drilled at various locations DESCRIPTION OF FRACTURE TREATMENT around the fractured well. Drill-stem tests, Micro and Sonic Logs, coring and sampling of formation cuttings N. J. Chittim Well No. 37-1, completed in the San were used to determine the presence of the fracture in Miguel No. 1 sand, Sacatosa field, Maverick County, these holes. The test holes were drilled at distances up Tex" was chosen for the field study. The San Miguel to 250 ft in a radial pattern around the fractured well. sand is a tight, well consolidated sandstone with an In addition to fracture areal extent and orientation, average porosity of 23 per cent. The permeability sand grain size before and after fracturing, erosion of ranges from 0.1 to 10 md, with a median permeability perforations and fracture thickness were studied. of 2,3 md. The sand thickness averages 23 ft and is located at depths of 1,150 to 1,700 ft throughout the INTRODUCTION field." The fracture treatment performed on Well 37-1 was as follows. The orientation," 2 areal extent"· and thickness'-o of 1. The well was drilled to a depth of 1,438 ft with artificially induced fractures in reservoir rock by hy­ native mud, and 511z -in. casing was set and cemented draulic means have been discussed in great detail in the oil industry in recent years. Methods for initiating to the surface. vertical" and horizontal" fractures have been tested in 2. The casing was perforated at 1,349 ft with a the laboratory and the field. Although the methods used fracture-initiating jet gun. This gun consists of six give successful well stimulation, good field data on the shots, 7 j16-in. diameter in a single horizontal plane. physical characteristics of the fracture are lacking in The jets were oriented in two groups of three, 180 0 the literature. It is recognized generally that properties opposed, The perforating device was designed to initi­ of a fracture, such as thickness, sand placement in the ate a fracture perpendicular to the wellbore. fracture12 and shape, may vary from reservoir to reser­ voir. 4000',----,----,------r----,---r----,-__-,-_----. This paper gives data on size, orientation and sand ~TART SAND placement in a large fracture initiated in a single plane 3000 I INJECTION in Sacatosa field, Maverick County, Tex. It is not in­ tended as a speculative study; rather, it is restricted

Original manuscript received in Society of Petroleum Engineers TUBING PRESSURE office Sept. 13, 1960. Revised manuscript received Feb, 13, 1961. Paper presented at 35th Annual Fall Meeting of SPE, Oct, 2-5, BREAKDOWN 1961. in Denver. rooD PRESSURE "Present address: Brown Oil Tools, Inc., Houston. INSTANTANEOUS SHUT IN PRESSUR lReferences given at end of paper. Discussion of this and all following technical papers is invited. 20 40 60 80 100 120 Discussion in writing (~hree copie3) may be sent to the office of the 140 160 Journal of Petroleum Technolo.qy, Any discussion offered after Dec. PUMPING TIME (MIN.) 31, 1961, should be in the form of a new paper, No discussion should exceed 10 per cent of the manuscript being discussed. FIG. I-PRESSURE CHART OF WELL No. 37-1.

APRIL, 1961 SPE 1571-G 371 3. Formation breakdown was obtained with lease in the apparatus. The 10-40 mesh cuttings were further crude 011 at a pressure of 2,300 psi at the surface. screened down to 20-40 mesh and acid washed, dried Fracture pressures recorded during treatment are shown and examined under the microscope for sand count as in FIg. 1. in prevlOUS tests. 4. After breakdown, a 1,000-gal blanket of fluid­ loss-treated dIesel oil was pumped ahead of the frac­ FIELD RESULTS ture flUid. PRESSURE CHART WELL 37-1 5. A mixture of 176,000 gal of diesel oil and lease Fig. 1 shows the pressure recording of the fracture crude oil treated with a fluid-loss agent was used as the treatment in Well No. 37-1. The surface recorded pres­ treating fluid, and 270,000 Ib of 20-40 mesh Poteet sure during breakdown was 2,300 psi. Since there was sand at a concentration of 1.5 lb/gal were added as little fluid movement at this time, the hydrostatic pres­ the fracture propping agent. sure of 470 psi for lease crude oil added to this surface 6. Injection rates during treatment averaged 30 pressure gave a bottom-hole pressure of 2,770 psi at bbl/min. the pertorations. The sudden increase in surface pres­ FIELD TEST PROCEDURE sure on the tubing occurred when the 30-bbl blanket of low fluid-loss oil was injected ahead of the sand, The test procedure used on the first 12 of the 14 and the pump rate was increased to 30 bbl/min. test holes was to drill to the top of the San Miguel After sand injection started, there was a sudden drop

No. 1 sand with a native mud system. From this point in treating pressure. Most of this drop in pressure may Downloaded from http://onepetro.org/jpt/article-pdf/13/04/371/2238182/spe-1571-g-pa.pdf by guest on 01 October 2021 to the bottom of the sand, either a rubber-sleeve core have been due to small enlargement or smoothing of barrel or a conventional core barrel was used to core the perforations by the sand. Either the pressure drop the producing sand. The formation cores obtained from across the perforations changed as the treatment pro­ this opel atIOn were examined for artificial fractures, gressed or less pressure was needed for the fracture presence of Pcteet sand grains and stress areas result­ propagation as the area enlarged. ing from the artificially induced fracture. At the end of the treatment, an instantaneous shut-in The M icrolog and the Sonic log were run on several pressure was recorded. The 300-lb drop in pressure of the cO/ed holes. The Microlog was run to obtain was a measure of the pressure drop acrcss the perfora­ formation lith.:logy data around Well 37-1. The Scnic tions. Calculating the treating pressure behind the per­ log with the Amplitude curve was an experimental tool forations in the fracture gives a treating gradient of deSigned to pick up formation anomalies such as dense 1.16 psi/ft. streaks and natural or artificial fractures." This tool was run as an experimental test for correlation with IMPRESSION BLOr.K OF other data indicating the presence of a fracture in the PERFORATIONS IN WELL 37·1 test holes. The perforations in this well, as described earlier, were made with a fracture-initiation gun consisting of During drilling and coring of each hole, samples of six 7/16-in. diameter holes oriented in a single hori­ formation cuttmgs were taken from the mud stream zC'ntal plane. The six shots are in two groups of three, at the surface. This test procedure was designed to each fired in opposite directions. obtain sand-grain data as the holes were drilled through An oriented impression of the perforations was taken the fracture. The sampling procedure consisted of to determine (1) direction, (2) degree of erosion and screening the formaticn cuttings thrC'ugh a 20-40 mesh (3) whether or not all perforations were open and tak­ sieve, acid washing these cuttings with HCI and, then, ing fluid during the treatment. A casing-leak detector examinmg the cuttings under a microscope for the was used to obtain these impressions. This tool is an presence of Pl\teet sand grains. A sand grain count of expandable rubber sleeve with a thin coating of plastic each sample was made, based on the number of grains material. The tool was pressured up from the surface of sand per gram of 20-40 mesh cuttings obtained from with a small hydraulic pump that inflated the rubber the screening. sleeve and pressured the plastic sleeve against the casing, The final test performed on each hole was to run a thus taking an impression of the perforations. drill-stem test over the entire test zone. Initial flow Fig. 2 shows a photograph of a section of the plastic pressures, final flow pressures and shut-in pressures sleeve containing the six impressions. were recorded on each well as another means of de­ termming whNher the fracture was present in the Analysis of the plastic impressions shows: (1) all well. Fluid samples from the drill-stem test also were six holes penetrated the pipe, (2) only slight erosion screened and analyzed for 20-40 mesh Poteet sand or smoothing of the perforations took place during grains. treatment, (3) no appreciable hole-size enlargement oc­ curred and (4) the perforations were oriented in an Core hole Nos. 13 and 14 were drilled to the 1 east-west direction. With a pump rate of 30 bbI/min top of the San Miguel sand, and 5 /2 -in. casing was during the fracture treatment and a pumping time of set at this point. The hole was loaded with lease crude 143 minutes, there was only a minor amount of perfo­ oil, and drilling continued through the sand zone. While ration erosion. These results indicate that with the rate drilling WIth oil, samples of the formation cuttings and volume used in most fracture jobs the perforations were taken throughout the sand zone. Selected intervals should remain relatively undamaged. of either 2 or 5 ft were drilled and all of the cuttings collected. This was accomplished by using a 40-mesh FRACTURES AND ANALYSIS screen apparatus attached to the shale shaker. Cuttings A large quantity of fracture sand was obtained on larger than to mesh were caught from the shale-shaker the drill-stem tests for Holes 13 and 3. Approximately lO-mesh screen. By flowing the effluent oil from the 600 to 700 Ib were recovered in 13, and samples of shale shaker upwards through the 40-mesh screen into this sand were analyzed for mesh size and degree of the circulatmg pit, 10-40 mesh cuttings were retained crushing. Control tests were run also on Poteet sand

372 JOURNAL OF PETROLEUM TECHNOLOGY TABLE 1 - GRAIN-SIZE DISTRIBUTION OF POTEET SAND 20-40 MESH FRACTURE SAND Before After Mesh Size Treatment Treatment 20 1.38 1.05 20 40 88.79 81.28 40 60 7.58 13.23 60 80 1.74 2.33 80 100 0.25 .53 100 120 0.05 .22 120 0.22 1.29" *Samp'es contain small amount of foreign matter from well.

sand pack is thinner and the sand grains are held more tightly by the overburden pressure, a greater degree of crushing may occur. The ease with which 600 lb of sand flowed into the test hole 100-ft from the original well indicates that the sand probably is distributed unevenly in the frac­ ture. This leads us to propose a "pillar-type" sand pack. The fracture is held open by "pillars" of sand. Other sand that is not held so tightly in place by the

overburden is free to flow easily into the wellbore. Downloaded from http://onepetro.org/jpt/article-pdf/13/04/371/2238182/spe-1571-g-pa.pdf by guest on 01 October 2021 SONIC LOG EVALUATION The Sonic log with the Amplitude curve was run on , ... a five of the 14 test holes as an experimental test tool. _..,lttu ...... -.-.. It has been observed that fractured zones sometimes ,.- cause "cycle skipping" on velocity of sound 10gs.11 The FIG. 2-IMPRESSlON BLOCK. cycle skippings that show up as sharp deflections to the left presumably result from absorption and reflections before fracturing for correlation purposes. of a large part of the sonic energy by the fracture. Table 1 shows the results of the split sample tests Fig. 3 shows the results of the five runs made and of both Poteet sand before and after fracturing. the depth at which an indication of a fracture was Slight variations are noted throughout the mesh range picked up. In all of the holes except Hole 7, there are of all samples. The largest amount of crushing (7 per definite indications of formation anomalies near the top cent) \\'as in the 20-40 mesh range. If crushing of sand of the San Miguel formation. These could be caused does occur, one would expect the larger grains to be by a fracture. None of these data was used in estab­ crushed first. This apparently is what happened, though lishing the location or depth of the fracture in the the amount of crushing was only 7 per cent-much final conclusion of results in any of the test holes. less than is often surmised. At what point during the treatment this crushing took place is not known, but CORING there are several possibilities. Some crushing could have The coring operations on Holes 1 through 12 using occurred in the pumps, while traveling down the an­ the rubber sleeve and the conventional core barrel gave nulus, while passing through the perforations, or in good core recovery. Numerous fractures were observed the fracture after the overburden settled down on the in the cores. Some of these breaks occurred during re­ sand pack. moval of the cores from the barrel. Other breaks could have been made during the drilling. A few could be JUdging from the large influx of sand into the well­ correlated with sand-count data and Sonic logs and bore during drill-stem testing, this portion could not may have represented the actual fracture. have been held tightly in place by the overburden pres­ sure. Therefore, the crushing that occurred probably SAND-COUNT DATA was not due to the overburden pressure as much as to Table 2 shows the sand-count data on the 14 test some other factor. In areas of the fracture where the wells. Also included are several development wells in

DEPTH CT-6 CT-7 CT-9 CT-II CT-12 1300

------~--~ ~

-ARROW INDICATES f LOCATION OF FRACTURE

FIG. 3-S0NIC LOG DATA.

APRIL. 1961 373 TABLE 2-SAND·COUNT DATA CT·l CT·2 CT·3 CT·4 CT·5 CT·6 Depth (It) Gr/Gm Depth(lt) Gr/Gm Depth (It) Gr/Gm Depth (It) Gr/Gm Depth (It) Gr/Gm Depth (It) Gr/Gm 1,329·53 Some 1,349·55 10 groins DST eir· Large 1,320·22 5 1,335 (C, D) 12 1,321·23 (C, D)~ grains Poteet eulaticn amount 1,322·24 5 1,336·37 13 1,325.26 46 but no sand. No. at 1,343 of 1,324·26 I 1,337·42 11 1,327·28 74 quantita- grams Poteet 1,326·28 2 1,342·52 2 1,345·46 34 five est. unknown 1,341·43 Some 1,328·30 2 1,352·55 10 1,353·54 20 Poteet 1,330·32 o Cire. 1,355 10 DST 39 1,332·34 o DST 1,335·55 6 1,334·36 o 1,336·38 2 1,338·40 o DST 1,322·40 80

CT·7 CT·8 CT·9 CT·l0 CT· 11 CT·12 1,332·32 (C, D) 119 1,306·08 (D) 310 DST 32 DST 62 1,322·23 (D) 85 1,318·20 (C) 8 1,333·36 55 1,312·13 276 1,328·29 93 1.323·25 23 1,336·40 61 1,321·22 (C) 106 1,334·35 (C) 71 1,325·27 14 1,340·43 37 1,324·26 105 1,336·38 19 1,330·32 6 1,343·46 35 DST 1,318·42 365 1,342 43 26 1,335·37 20 1,346·49 36 1,348·49 13 DST 1,317·42 27 1,349·52 85 1,351·52 21 DST 1,333·52 160 1,353·54 24 DST Top 26 DST Bottom 55

CT·13 CT· 14 38·7 66·10 66·12 1,310·15 41 1,334.36 (C) 2,550 1,348 16 778 (A) 34 348 13 1,315.20 21 1,336·38 1,515 1,358 8 848 (A) II 723 27

1,320·30 (C) 11 1,338·40 335 1,368 4 1,481 (D) 22 807 23 Downloaded from http://onepetro.org/jpt/article-pdf/13/04/371/2238182/spe-1571-g-pa.pdf by guest on 01 October 2021 1,330·32 9 1,340·42 175 1,378 20 1,491 65 1,418 23 1,332·34 5 1,342·44 100 1,388 16 1,516 (C) 10 1,433 (D) 52 1,334.36 3 1,344·46 25 1,398 0 1,522 (C) 9 1,443 46 1,336·38 6 1,346·48 60 1,408 (C) 12 1,527 (C) 9 1,453 16 1,338·40 4 1,348·50 65 1,468 6 1,463 8 1,340.42 5 1,350·54 13 1,478 0 1,476 (C) 12 1,342·44 0 1,354·58 13 1,343·53 14 1,344·46 2 1,358·62 87 1,373·1,403 5 1,346.48 0 1,362·66 12 1,403·33 7 1,348·50 0 DST No. I 2,900 1,433·63 0 1,350·52 0 1,331·46 1,352.56 0 DST No.2 1,075 1,356.61 1 1,331·66 1,361·66 0 1,366.71 8 1,371·75 1,681 DST No. I No solids DST No.2 Large amt. of sand recovered (A) Olmos sand. (B) Bit ehange·eire. bottoms. (C) Son Miguel (first sample). (D) Top 01 core. the Sacatosa field in which sand grain counts were sequence was made except for the first three holes. Test made during drilling operations. This was done to locations after these first three holes were based on the establish a base count of Poteet-like sand grains ob­ resulting data as the holes were driIIed and tested. The tained from the Olmos sand located at a depth of 600 primary purpose of this field study was to determine to 900 ft. Since the Olmos sand grains are in the 20-40 the direction or orientation of the fracture and its mesh range and do resemble the sub angular Poteet areal extent. sand, this base count was necessary for a more accurate The shadowed holes plotted in Fig. 5 represent the evaluation. Identification of the Poteet sand grains in holes in which sufficient data were obtained to place the drilled solids collected in the sampling apparatus them in the fracture. As discussed in the general pro­ was made on the basis of shape or angularity, internal cedure earlier in this paper, several methods were characteristics, inclusions, fracture planes and staining used as criteria for determining whether or not the techniques. A comparison was made of the similarity of fracture was encountered. Holes 3, 4, 8, 13 and 14 are Poteet and San Miguel No. 1 sand grains. A distinct classified as in the fracture because of positive driII­ difference was noted in the size, shape and crystal stem tests. An example of a positive drill-stem test is facets of the San Miguel sand grains. All of the San shown in Fig. 4. Holes 6, 7 and 11 are classified as Miguel sand grains are smaller than 40 mesh, with the having at least one good positive test (sand count), large majority being in the 60-80 mesh range. They also which indicates that they penetrated the fracture. are more angular in shape than the Poteet fracture Holes 1, 2, 5, 9, 10 and 12 gave no positive indica­ sand. tions of being in the fracture system. That does not A statistical average of the Poteet-like sand grains mean that smalI cracks might not have been in any or per gram of 20-40 mesh cuttings is 21, and 95 per cent all of them. In many of the first 12 holes, a fracture of the time the count should be below 65 grains/gm. could have been mudded-off easily during drilling, These data from Table 2 have been used as one cri­ which would have a negative drill-stem test. It is inter­ terion in determining whether the fracture was or was esting that the Sonic log indicated a fracture in Holes not encountered in any specific welL Inspection of the 9 and 12 while the other techniques gave negative re­ table shows that Holes 3, 6, 7, 8, 11, 13 and 14 have sults. It is also hard to accept a definite fracture in high sand counts, indicating they are probably in the Hole 13 without assuming a probable fracture in Holes fracture. 1 and 5. It can be seen readily from Fig. 5 that the fracture FRACTURE ORIENTATION AND system is horizontal. Based on data to date, the major AREAL EXTENT strike of the fracture is to the west. The complete fracture pattern has not been determined exactly. How­ Fig. 5 is a location plot of the 14 test holes around ever, enough area has been determined positively to the fractured Well 37-1. No pre-planned well-location show as much as that calculated from the Howard

374 JOURNAL OF PETROLEUM TECHNOLOGY CT-12 NEGATIVE w B C a:: :::> Cfl Cfl w a:: a.. A E TIME

14 CT-13 POSITIVE w w a:: :::> Cfl Cfl w A E a:: a..

TIME

CT-12 CT-13 Downloaded from http://onepetro.org/jpt/article-pdf/13/04/371/2238182/spe-1571-g-pa.pdf by guest on 01 October 2021 A Initial Hydrostatic Mud Pressure 711 438 LEGEND: B Initial Flaw Pressure 20 97 !!Ix. DEFINITE EVIDENCE "

APRIL, 1961 375 2. The areal extent of fracture was at least as large 3. Reynolds, J. J., Bocquet, P. E. and Coffer, Henry F.: as that calculated from the Howard and Fast equation.' "Conversion of Crude Oils to Low-Fluid·Loss Fracturing Fluids", Drill. and Prod. Prac., API (1955). It extended more than 250 ft from the well bore. 4. Howard, George C. and Fast, C. R.: "Factors Controlling 3. The fracture was not uniform in all directions or Fracture Extension", Pet. and Nat. Gas Div., CIM Spring in thickness. Meeting (May, 1957). 4. The perforations were only slightly eroded during 5. Davis. J. G., Reynolds, J. J. and Coffer, H. F.: "The Ef­ fect of Fluid Loss on Fracture Extension", Paper pre­ the fracturing job. sented at SPE Fall Meeting (Oct., 1955) in New Orleans. 5. Fracturing sand was not changed appreciably 6. Halliburton Co.: Fracture Guide. during the fracturing job. 7. Dowell Div. of the Dow Chemical Co.: Fracture Guide. 8. The Western Co., Inc.: Fracture Guide. ACKNOWLEDGMENT 9. Walther, H. C. and Kendig, R. L.: Fracture Guide, Con­ tinental Oil Co. The authors wish to express their appreciation to 10. Clark, Roscoe C., Jr. and Reynolds, Jack J.: "Vertical Hydraulic Fracturing for Increasing Oil and G,as Produc­ K. H. Stimpson for the assistance given during the tion", Drill. and Prod. Prac., API (1954). field tests and to R. J. Cavanaugh for his assistance 11. Huitt. J. L.: "Hydraulic Fracturing with the Single-Point in analyzing and collecting field data. Also, we wish Entry Technique", Jour. Pet. Tech. (March, 1960) XII, to thank Continental Oil Co. for granting permission No.3, n. to publish this paper. 12. Darin, S. R. and Huitt, J. L.: "Effect of a Partial Mono­ layer of Propping Agent on Fracture Flow Capacity",

Trans., AIME (1960) 219, 31. Downloaded from http://onepetro.org/jpt/article-pdf/13/04/371/2238182/spe-1571-g-pa.pdf by guest on 01 October 2021 REFERENCES 13. Knutson, C. F., Timko, D. J., Bohor, B. F. and Conley, F. R.: "Characterization of the San Miguel Sandstone by 1. Hubbert, M. King and Willis, David G.: "Mechanics of a Coordinated Logging and Coring Program", Paper Hydraulic Fracture", Trans., AIME (1957) 210, 153. 1578·G presented at 35th Annual Fall Meeting of SPE 2. McGuire, W. J., Jr., Harrison, Eugene and Kieschnick, (Oct. 2·5, 1960) in Denver. W. F., Jr.: "The Mechanics of Formation Fracture Indue· 14. Tixier, M. P., Alger, R. P. and Doh, C. A.: "Sonic Log- tion and Extension", Trans., AI ME (1954) 201, 252. ging", Trans., AIME (1959) 216, 106. ***

376 JOURNAL OF PETROLEUM TECHNOLOGY