Blaster design software helps select jetting tool geometry— drift ring, nozzle head, port size and configuration— required fluid rates, expected treating pressures, abrasive material concentrations and scale-removal rates. The soft- ware also estimates consumables, such as gelling agents, mixing products and abrasive materials. The coiled tubing BHA encountered scale at 2,546 m [8,353 ft] in the Petrobras well. Using a xanthan-gelled brine and 3%-by-weight Sterling Beads abrasive particles, the Jet Blaster tool achieved a cleanout rate of 12 to 15 m/hr [39.4 to 49.2 ft/hr] from 2,546 to 3,087 m [10,128 ft]. Pumping at 0.23 to 0.27 m3/min [1.5 to 1.7 bbl/min] with circulating pump pressures of 24.1 to 27.6 MPa [3,500 to 4,000 psi], this part of the job required 36 hours and three jetting tools. At 3,087 m, 60 m [197 ft] below the tubing and inside the 7-in. liner, the jetting tool was replaced with a PDM and a 21
⁄ 2 -in. three-step mill.
This fi nal stage took 12 hours to clean out 43 m [141 ft] to 3,130 m [10,269 ft] and completely consumed the mill.
The total operation generated about
66,000 lbm [29,937 kg] of debris— 6,000 lbm [2,722 kg] of scale and 60,000 lbm [27,216 kg] of abrasive particles— that were captured in the platform production separator. After the job, other platform wells had to be shut in for a short time to clean the production separator. Most scale-removal jobs now use a temporary separa- tor to capture solids before they reach the production separator.
Scale Blaster technology effectively removed
barium sulfate scale from completion tubing and hardware in conditions under which conven- tional methods had failed in the past. As a result, oil production increased 1,025%, which resulted in a 19-day payout.
8. Crabtree M, Eslinger D, Fletcher P, Miller M, Johnson A and King G: “ Fighting Scale— Removal and Prevention,” Oil eld Rev iew 11, no. 3 (Autumn 1999): 30– 45.
9. Quiroga MHV, Calmeto JCN, Assis CAS, Pinto SL and Santos F: “ Hard Scale Mechanical Removal: A Solution for Brazilian Offshore Operations,” paper SPE 89627, presented at the SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, Texas, USA, March 23– 24, 2004.
10. Allouti A, Ben Amor B, Ferhat A, Oettli M, Ortiz A and Wood J: “ Coiled-Tubing-Conveyed Fracturing Technique Provides Economic Alternative to Workover Rigs in Stimulation Campaign,” paper SPE 89446, presented at the SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, Texas, USA, March 23– 24, 2004.
11. Degenhardt KF, Stevenson J, Gale B, Gonzalez D, Hall S, Marsh J and Zemlak W: “ Isolate and Stimulate Individual Pay Zones,” Oil eld Rev iew 13, no. 3 (Autumn 2001): 60– 77.
12. Gutor C, Al-Saleem A, Rieger B and Lemp SP : “ New Life for Old Wells: A Case Study of Re-Stimulating Gas Wells Using Fracturing Through Coiled Tubing and Snubbing Techniques,” paper SPE 81730, presented at the SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, Texas, USA, April 8– 9, 2003.
It is common for wells in mature fields to experience scale deposition. Blaster services have been applied in several other locations to save time and money, including Duri field in Indonesia and several North Sea fi elds. In addi- tion to use in wellbore cleanouts, CT has become an important tool in formation stimulation.
Reservoir Remediation
In Algeria, Sonatrach stimulates deep high- pressure, high-temperature (HPHT) wells of the Hassi Messaoud field using coiled tubing-con- veyed fracturing and new packer technology.10 Reservoir conditions allow low-rate, high- pressure hydraulic fracturing treatments, which significantly increase productivity and prolong the economic life of these wells. Unfortunately, many wells require remedial cement squeezes or tubing replacement to address tubular-integrity problems before stimulation operations can begin.
In the past, problems with conventional pack- ers limited fracturing success because of differential pressures in excess of 9,000 psi [62.1 MPa] across the isolation packer. Some treatments resulted in costly fi shing operations. CoilFRAC stimulation through coiled tubing treatments provided an alternative to conven- tional workover rigs (right).11
The availability of
CT units was an additional advantage. Coupled with more reliable mechanical pack-
ers
for downhole isolation, CT-conveyed fracturing protects wellbore tubulars from high treating pressures and abrasive proppants. CoilFRAC techniques are applicable for initial stimulation treatments in new wells, stimulation of bypassed pay and restimulation of previously treated intervals.12
In October 2001, Sonatrach performed the
fi rst CoilFRAC treatment in Hassi Messaoud Well OMP843. Completed with a 41 perforated liner and 41
⁄ 2 ⁄ 2 pressure between the 7-in. and 95 Straddle-isolation tool -in. cemented and
-in. tubing, this well had ⁄ 8
-in. casing. The
CT packer was set at 10,660 ft [3,249 m] above a profile nipple in the production tubing. The treatment placed a total of 21,464 lbm [9,736 kg] of 20/40 proppant in the formation at a maximum concentration of 3.1 pounds of proppant added (ppa) per gallon of treatment fl uid.
The average surface treating pressure was 8,600 psi [59.3 MPa]. A 13,100-ft [3,993-m] 23
⁄ 8 -in.
coiled tubing string isolated wellbore completion tubulars. The packer withstood a maximum 8,800-psi [60.7-MPa] differential pressure at 9 bbl/min [1.4 m3/min]. Prefracture production was 860 B/D [137 m3/d] of oil; postfracture pro- duction was 2,280 B/D [362 m3/d] of oil. The
Fracture Pay zone 2 Pay zone 3
> Selective isolation and stimulation. Conventional hydraulic fracturing maximizes fracture height, often at the expense of fracture length and complete stimulation coverage. Coiled tubing-conveyed fracturing overcomes these limitations and allows engineers to design optimal fractures for each pay zone. CoilFRAC stimulations can be performed with a single mechanical packer and sand plugs (top) or selective straddle tool assemblies (bottom).
Pay zone 1 Sand plug 1 Pay zone 3
treatment, including deferred production, paid out in 39 days.
At that time, this was the deepest well frac- tured through coiled tubing. Excessive hydraulic forces caused the packer to release twice during prejob injectivity and treatment-calibration tests. Bottomhole pressure gauges verifi ed the model- ing of downhole forces and guided modifi cations to the CT packer.
Based on CoilFRAC experience from three Hassi Messaoud field wells, including Well OMP843, stimulated between October 2001 and January 2003, Schlumberger made several packer improvements. Development of the OptiSTIM MP mechanical packer for stimulation
Packer Pay zone 1 Fracture Sand plug 2 Pay zone 2
Spring 2004
47
Page 1 |
Page 2 |
Page 3 |
Page 4 |
Page 5 |
Page 6 |
Page 7 |
Page 8 |
Page 9 |
Page 10 |
Page 11 |
Page 12 |
Page 13 |
Page 14 |
Page 15 |
Page 16 |
Page 17 |
Page 18 |
Page 19 |
Page 20 |
Page 21 |
Page 22 |
Page 23 |
Page 24 |
Page 25 |
Page 26 |
Page 27 |
Page 28 |
Page 29 |
Page 30 |
Page 31 |
Page 32 |
Page 33 |
Page 34 |
Page 35 |
Page 36 |
Page 37 |
Page 38 |
Page 39 |
Page 40 |
Page 41 |
Page 42 |
Page 43 |
Page 44 |
Page 45 |
Page 46 |
Page 47 |
Page 48 |
Page 49 |
Page 50 |
Page 51 |
Page 52 |
Page 53 |
Page 54 |
Page 55 |
Page 56 |
Page 57 |
Page 58 |
Page 59 |
Page 60 |
Page 61 |
Page 62 |
Page 63 |
Page 64 |
Page 65 |
Page 66 |
Page 67 |
Page 68 |
Page 69 |
Page 70 |
Page 71 |
Page 72 |
Page 73 |
Page 74 |
Page 75 |
Page 76