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1、spe 50614massive fracture stimulation in deep, high-pressure athel formationsau-wai wong, spe, steve ford, spe, and bob turner, spe, petroleum development omancopyright 1998, society of petroleum engineers inc.this paper was prepared for presentation at the 1998 spe european petroleum conference hel

2、d in the hague, the netherlands, 2022 october 1998.this paper was selected for presentation by an spe program committee following review of information contained in an abstract submitted by the author(s). contents of the paper, as presented, have not been reviewed by the society of petroleum enginee

3、rs and are subject to correction by the author(s). the material, as presented, does not necessarily reflect any position of the society of petroleum engineers, its officers, or members. papers presented at spe meetings are subject to publication review by editorial committees of the society of petro

4、leum engineers. electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the society of petroleum engineers is prohibited. permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations

5、 may not be copied. the abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. write librarian, spe, p.o. box 833836, richardson, tx 75083-3836, u.s.a., fax 01-972-952-9435.abstractthe deep, high pressure athel reservoirs are located in the south oman salt bas

6、in. due to low permeability, un-stimulated well rates are low. recently, two wells have been stimulated with the largest hydraulic fractures in the middle-east. the post-frac production lives up to expectation. the well design and stimulation approach has significantly improved the economic viabilit

7、y of the athel accumulation.introductionthe athel silicilyte is found in the south oman salt basin1, where thick slabs up to 400m of silicilyte are stratigraphically encased within salt and shale (fig. 1). the hard silicilyte rock is composed of mainly micro-crystalline silica with low matrix permea

8、bility in the horizontal direction (0.02md or less). there is virtually no permeability in the vertical direction. considering the reservoir depth of approximately 4 km, the porosity is well preserved, ranging from 0.15 to 0.25. the hydrocarbon is light, volatile oil (48o api) with associated gas an

9、d contains 1.5 mol% h2s and 3 mol% co2. because of the encasement within the salt domes, the reservoir is nearly geostatically pressurised, with an initial pressure gradient of 19.8kpa/m. the reservoir temperature is not particularly high, around 100 oc at 4,000m.al noor and al shomou fields are two

10、 of the athel silicilyte prospects discovered in 1989 and 1995, respectively (fig. 2). to-date six wells have been drilled in the al noor structure and four wells and side-tracks in the al shomou structure.typical un-stimulated well rates in the tight athel reservoir range between 40 and 110m3/day.

11、therefore, higher initial well rates, resulting in higher recoverable volumes are required for optimum field development. to this end, different well designs such as massive hydraulic fractures, slanted wells, multi-laterals and multi-fracced multi-lateral wells have been considered. the first devel

12、opment wells will be hydraulically fractured, with pre- and post-frac production tests to accurately quantify the resultant productivity improvement.in 1996, multiple hydraulic fracture treatments in al noor-4 were carried out. however, due to a lack of pre-frac production data and the apparently po

13、or reservoir quality encountered, the post-frac productivity improvement could not be fully appraised. but it indicated that fracture stimulation could provide a promising method to increase well productivity in the athel.in 1997, al shomou-3 and al noor-6 were openhole production tested, worked-ove

14、r and fracture stimulated. one of the prime objectives was to further demonstrate that massive hydraulic fracture stimulation in the athel could be successfully applied with significant post-frac productivity improvement. this would lead to the al shomou field reserves booking, and the approval to c

15、ommence phase 1 field development, a pre-cursor to a full development of the al noor and al shomou fields. the planning and execution of high pressure, deep well fracture stimulation in a remote desert environment provide significant challenges. in this paper, the key aspects of well and fracture de

16、signs, and the salient features of the entire operation are outlined. finally, the results of the treatments, post-frac production, and future optimisation are described.fracture designthe fracture design is based on the understanding that in low permeability reservoir the productivity improvement i

17、ncreases with fracture length, hence the aim is to create the longest/biggest fracture that is practical. generally, the width has a minor effect on the productivity; and therefore, high proppant concentrations are not essential. figures 3 and 4 show the estimated initial productivity improvement du

18、e to increase in fracture length and width, respectively.ideally, the fractures should cover the whole of the reservoir zone in order to maximise inflow performance. the number of treatments required to achieve this depends on the size of the fractures. in al noor-4, three multiple fractures each pr

19、opped with an average 70,000kg of proppant were required. for al noor-6 and shomou-3 treatments, we proposed bigger fractures, with approximately 250,000kg of proppant per frac. consequently, the number of fracture treatments per well is reduced from four to two.each fracture is initiated from a 6m

20、perforated interval. after perforating the lower interval, a mini-frac test is conducted for data gathering, then the main fracture treatment is pumped. the lower fracture treatment includes the placing of a precise column of proppant plug in the wellbore to provide isolation for the upper zone to b

21、e perforated and fracture stimulated.the design employs a radial fracture growth model. this assumes that there are no major stress and stiffness contrasts in the silicilyte. key inputs for the model such as rock stiffness properties, in-situ stress, and fluid leak-off data are obtained from laborat

22、ory rock-mechanical core tests and extensive field mini-frac tests. mini-frac test. a typical mini-frac injection test starts with the pumping of a small volume (15m3) of acid to clean off any tubing dirt/scale. this is immediately followed by pumping a water-base linear gel (made from a guar gum de

23、rivative) at high rate (6.5m3/min), to breakdown the formation. after breakdown, a series of step-down and step-up on pump rates is performed to assess the near wellbore friction behaviour. subsequently, 80m3 of cross-linked gel are pumped to create a mini-frac. the pump is instantaneously shut-in a

24、t the end of the mini-frac, and the pressure decline behaviour is monitored to provide data on fluid-leak-off rate and fracturing pressures. finally, the test is concluded with the pumping of two low concentration proppant slugs. detailed analysis of the all the injection tests is carried out and th

25、e results are used to further refine the main treatment design.main fracture design. there are essentially two main stages in the main fracture treatment. firstly, a large pad volume of cross-linked gel fluid is pumped to fracture open the formation. depending on the actual fluid leak-off value obta

26、ined from the mini-frac analysis, typical pad volume ranges between 650 to 900m3. once a fracture of sufficient size is created, proppant (20/40 mesh size, medium strength ceramic material) is mixed into the cross-linked gel and pumped downhole to prop open the fracture. the proppant concentration i

27、s designed to increase in steps from 250 to 850kg/m3 ( 2 to 7 lbs/gal) to provide an optimum fracture width. the total pumping time is approximately 3.5 hours. a typical main pumping treatment is shown in figure 5.well designin al noor-4 fracture treatments, there were uncertainties surrounding the

28、likely treatment pressures. therefore, a 5.1/2 frac string was used to allow for high pump rates whilst maintaining surface pressure below 103,500kpa (the rating of the surface equipment). after the fractures were placed the well was worked over to recover the frac string and install a 3.1/2” produc

29、tion completion. the experience of al noor-4 fracture treatments indicates that a slimmer design can be used. thus al shomou 3 and al noor-6 are completed with 4.1/2 frac/production string, enabling an overall slimming down of the well design2. after fracture stimulation, the same 4.1/2 tubing strin

30、g is used as a production string, hence removing the need for a tubing change-out workover after fracturing and before production testing the well. this gives a significant cost saving of approximately us$2 million per well, and also avoids the risk of formation impairment during a workover.planning

31、 and executionone of the main hurdles facing such a large operation is the mobilisation of equipment and materials to the athel exploration/appraisal area. al shomou and al noor fields are some 500 km from the frac contractor base. for al shomou-3 alone, over 100 loads of equipment and supplies were

32、 required to complete the 2 fracture treatments, totalling some 100,000km trucking distance (equivalent to 2.5 times around the world). the frac fluid was pre-mixed and stored in the frac tanks. during fracture treatment this was pumped to the blender unit where it was mixed with proppant and other

33、additives before being discharged to the treatment lines. total material storage capacity on site comprised 22 fluid tanks (sufficient to pre-mix and store 1300m3 of treatment fluid and 400m3 power water for the intensifier pumps) and 3 proppant silos capable of storing and delivering up to 400,000k

34、g of proppant to the blender for each treatment. figure 6 shows the layout of frac equipment.pumping equipment had to be capable of delivering 1300m3 fluid loaded with up to 300,000kg proppant at flowrates of 6.5m3/min and treatment pressures of up to 90,000kpa. with such an abrasive treatment fluid

35、, the reliability of the pumps and equipment becomes especially crucial when pumping time is as long as 3.5 hours. for these treatments intensifier pumps were the preferred choice. these are essentially pressure multipliers delivering fluid at 3 times the input pressure and 1/3 of input flowrate. in

36、 order to achieve the required 6.5m3/min treatment flowrate and 90,000kpa treatment pressure, power-water had to be supplied at 19.5m3/min and 30,000kpa from pumping equipment with a maximum capacity of 21,000 horsepower. the main advantage that intensifiers have over standard cementing-type pumps i

37、s their reliability. due to their pumping action, intensifier operations generally face fewer problems associated with wear and tear and therefore reduce the chances of failure. resultsin al shomou-3 a total of 525,000kg ( 1 million lbs.) of proppant was pumped to prop two massive fractures. in al n

38、oor 6, due to the higher reservoir permeability (higher fluid leak-off), the pad volume required was approximately 20% more than al shomou-3. the total proppant pumped for the two fractures was 459,000kg. key fracture design and pumping parameters for the two wells are summarised in tables 1 and 2.

39、the overall design methodology, planning and execution strategies proved to be effective, resulting in the successful placement of two massive propped fractures in each well. it is worth noting that all these were achieved without any lost time incidents, i.e. perfect safety record.post-frac product

40、ionthe post-frac production lives up to expectation and shows that productivity improvement factors of 7 to 9 times over initial un-stimulated rates are achievable, in reasonable agreement with calculation.at the time of writing, al shomou-3 has been opened up for production test. initial flow after

41、 2 days was more than 700m3/day and declined (as expected) to 480m3/day after 5 days at 13,200kpa tubing head pressure. after 7 days the well was producing at a steady rate of 395m3/day, with tubing head pressure at 12,500kpa. for comparison, the pre-frac test in this well gave an initial rate of 80

42、m3/day after 2 days and 60m3/day after 7 day (fig. 7). further production testing and data gathering will be carried out for both wells, with fluid sampling and production logging.fracture diagnosticthe knowledge of fracture geometry and orientation is vital to athel field development. it has signif

43、icant impact on fracture treatment optimisation and well placement, particularly in the context of an eor project. in addition, it is important to the calibration of a dynamic reservoir simulation model. minimum in-situ stress. the key controlling parameters for fracture dimensions and orientation a

44、re the magnitude and direction of minimum in-situ stress. since fracture propagates in a direction perpendicular to the minimum in-situ stress, it is important to establish that the minimum in-situ stress is in a horizontal direction, so that vertical fractures have indeed been formed. however, beca

45、use of the encasement within salt, it is likely that there is little contrast between the three principal field stresses. hence, it may not be straightforward to determine the fracture orientation. figure 8 shows the minimum in-situ stress as measured from the mini-frac tests. generally, they vary b

46、etween 21.5 kpa/m to 23 kpa/m, very close to some estimates of the overburden stress (integration of density log). this has two possible implications. firstly, if the minimum in-situ stress is horizontal, then indeed there is a lack of clear stress contrast and it will be difficult to determine frac

47、ture direction (vertical or horizontal) by comparing the stress magnitudes. secondly, the measured minimum in-situ stress may be oriented in the vertical direction and therefore fractures are in the horizontal direction. this uncertainty needs to be further quantified. to this end, an integrated stu

48、dy are being conducted, involving core analysis, borehole log images of drilling induced fractures, borehole breakouts, structural geology and geomechanics simulation. in addition, a fracture mapping tool based on micro-seismicity measurement is being developed for used in the athel environment3. we

49、ll test analysis. in the analysis of al shomou-3 post-frac well test data, key reservoir input parameters such as initial pressure and permeability characteristics are fixed at the known values derived from pre-frac well test analysis. guided by these parameter constraints, a series of iterations ha

50、ve been carried out to obtain the overall best match to the post-frac production data4. the back-calculated average fracture half-length (radius) for the two fractures is approximately 86m, in good agreement with the fracture model prediction (table 1). these analyses, involving pre- and post-frac w

51、ell test data, and other techniques for fracture diagnostic in the athel will be discussed in detail in a separate publication. suffice to note that from the well test analyses, the fracture model employed has predicted the fracture geometry with reasonably good accuracy, and vertical fractures have

52、 been formed in al shomou-3. improvement and optimisationthe feasibility of stimulating wells with a single massive fracture is being investigated. this would avoid having to place an isolation proppant plug in between fractures, and hence reduce the need of deep well, high pressure coil tubing oper

53、ation and its associated risks. a single massive fracture stimulation is particularly attractive if it can be performed in a barefoot completed well (i.e. without a cemented liner). this would remove the need for a workover between pre- and post-frac testing, and reduce costs and risks in running, c

54、ementing and perforating the liner. pumping pressures observed during the frac treatments were lower than predicted, employing less than half of the 21,000 horsepower available on site. even with allowance for excess horsepower to cope with pump failures, there is scope for reduction in pumping capa

55、city and hence, scope for cost reduction for future operations.in future fracture treatment of similar size or larger, the capability to mix gel fluid on-the-fly will be employed. this reduces the number of tanks required and also reduces the amount of waste generated at the site. for example, it re

56、duces the amount of waste resulting from unpumpable volumes in the bottom of tanks, or due to the disposal of large quantities of pre-mixed gel in the event that an operation is delayed or cancelled for any reason.concluding remarksbased on the rates obtained, with further subsurface studies and production simulation, substantial oil reserves in al shomou field were booked. al noor phase 1 field development was initiated at the beginning of 1998, employing massive hydraulic fracture stimulation in the well design. acknowledgementsthe success achieved is the result of a concer