The ability to restimulate completions without a service rig offers significant cost savings.

The capacity to perform remedial stimulation treatments on subsea wells without rig intervention can be attractive from a cost and mobilization standpoint.
Two such treatments were performed recently on two subsea producing wells tied to the miniature tension-leg platform (TLP) at the Gulf of Mexico's Morpeth Deepwater Development Project in 1,700-ft (519-m) waters.
Initially, production from one of the Morpeth wells was satisfactory at more than 10,000 b/d. However, after an 11-month production decline, the rate had fallen to an unacceptable 3,000 b/d. Analysis of formation mineralogy from an offset well in the same formation indicated a strong tendency toward fines migration.
A hydrofluoric sandstone acid treatment incorporating a CO2 preflush process for matrix oil well stimulation was recommended. The possibility of performing the matrix CO2 treatment through the flow line from the TLP was determined to be feasible.
Procedures were developed for incorporating permanent downhole pressure gauges for rate and pressure control. The first stimulation treatment restored a sustained production rate of 7,000 b/d.
After the first well was successfully restored, a second well showed signs of damage, possibly resulting from fines migration. A design and execution plan was prepared based on the lessons learned from the first well treatment. The execution of the second treatment improved upon that of the first, but the production response did not equal the dramatic increase observed in the first well.
Fines problem identified
The Morpeth project consists of three subsea oil wells and, for pressure maintenance, one subsea seawater injection well. The wells flow back to the TLP through individual flexible flow lines.
A sandstone formation at about 15,200 ft (4,626 m) TVD is the oil source. The formation is comprised of unconsolidated, fine-grain sandstone. A substantial amount of migrating clays in the silt and mudstone layers indicated clay fines migration could be a potential problem. Two of the three production wells are cased-hole frac-pack completions, while the third is an openhole gravel-pack completion. The injection well is an openhole frac-pack completion.
The producing openhole gravel-pack completion had an initial production rate of 10,000 b/d (Figure 1). A pressure buildup analysis showed permeability at 1,500 md, skin at 13 and drawdown pressure at 200 psi. Nine months later, the production rate had dropped to 3,000 b/d. At that time, a pressure buildup analysis showed permeability at 260 md, skin at 21 and drawdown pressure at 1,700 psi, at a rate of 7,500 b/d. The actual production rate was limited to 3,000 b/d.
An injectivity test plan was developed to determine whether a fines migration damage mechanism existed and whether injectivity could be established into the formation. For the test, 50 bbl of dead crude oil was pumped from the TLP through the flow line and into the completion at 0.5 bbl/min. This test verified that fluid could be so pumped. In addition, when the well was again placed into production after the injection, PI increased slightly. This increase indicated the damage mechanism probably was a result of fines migration.
Acidizing chosen as solution
For fines migration, the best solution appeared to be the application of a sandstone acidizing treatment. Performing the treatment through the flow line was preferable, if the impact on the hardware in the production system would be negligible. Also, this solution would prevent the need for the costly mobilization of an intervention rig.
A review of applicable acidizing techniques led to the inclusion of a CO2 formation-conditioner preflush ahead of the sandstone HF acid treatment. The technical literature documented the following benefits of this formation pretreatment method:
• CO2 will displace the formation crude oil, improving the relative permeability of the formation to acid, which reduces the preferential stimulation of formation water;
• when the oil is removed, the CO2 formation conditioner improves the effectiveness of stimulation treatments on oil and high-condensate gas wells;
• the CO2 reduces or eliminates the need to treat spent acid returns for emulsion in production facilities; and
• CO2 in the formation provides a source of energy to expedite the recovery of spent acid and improves cleanup by reducing the contact time between spent acid and formation.
The formation mineralogy was reviewed for compatibility with HCl and HCl/HF acids, as well as ammonium chloride overflush and displacement fluid. The compatibility issues addressed included ion-exchange transformation of brines, decomposition of clays in HCl, precipitation of fluosilicates, removal of carbonates to prevent precipitation of complex aluminum fluorides, silica-gel filming, colloidal silica gel precipitation and separation of various stages of the treatment in the formation matrix.
Based on the formation analysis, the following treatment sequence was proposed:
• 2,000 gal xylene with surfactant (25 gal/ft);
• 16,000 gal liquid CO2 (200 gal/ft);
• 6,000 gal 15% HCl (75 gal/ft);
• 8,000 gal 13-1/2-1-1/2% HCl/HF (100 gal/ft); and
• flush to open hole 5% NH4Cl (18 gal/ft).
Because the treatment was critical to the development's overall production, the treatment was lab-tested on core samples from an offset well. One plug was taken from the sandstone area and another was taken from the silt and mudstone area of the cores.
The following procedure was used for acid compatibility testing:
• the cores were flushed with synthetic formation brine and formation crude oil to establish initial water and oil saturations;
• permeability was established at reservoir temperature using formation crude oil;
• the acid treatment was pumped through each core plug; and
• permeability was redetermined using formation crude oil.
Results of the treatment testing showed a 54% increase in the permeability of the high-permeability sandstone core and a 13% increase in the permeability of the lower-permeability silt and mudstone core.
Hardware compatibility
During treatment, flow-wetted hardware components between the TLP production manifold and the gravel-pack screen at the formation face are exposed to live acid. These components also may be exposed to acid during flowback. Because of this exposure, all components in the candidate wells had to be acid-compatible. These included the TLP production manifolds and valves, the flexible flow line, the 10K horizontal tree, the hanger and the subsea valves.
In addition, the temperatures and pressures with CO2 and the other treatment fluids were modeled. Tubing-movement scenarios also were developed for review.
Live acid flowback was expected with the small overflush; therefore, a corrosion inhibitor that would remain in the acid during flowback was selected. The corrosion inhibitor would protect the wetted surfaces during flowback, as well as during the original acid injection.
At the same time, a maximum bottomhole pressure limitation was established to prevent formation fracturing. The estimated fracture gradient was based on gradients observed during the frac-pack completion of the offset wells and the reservoir pressure of the well to be treated.
The length of the openhole interval required a review of diversion options, such as foam and rate. A decision was made to divert the treatment with the pump rate to keep the execution simple. The treatment, pumped at the highest rate possible, would maximize diversion across much of the exposed formation.
Monitoring permanent electronic bottomhole pressure and temperature gauges on the TLP removed friction concerns in the determination of bottomhole treating pressure, and also allowed maximum rate diversion.
Stimulation treatment
Because space was limited on the TLP and large volumes of CO2 and acid would be pumped - possibly at fairly high rates for a matrix treatment - a marine stimulation vessel was chosen to perform the operation. Dynamic positioning was required because the TLP would not support the mooring of such a large vessel.
Pressure and rate vs. time plots of the treatment are shown in Figure 2.
During the first treatment, when flowback was performed and treatment fluids were recovered, the well was again placed into production. A significant amount of live acid was noted in the flowback. After 2 weeks of production at 7,500 b/d, a post-treatment pressure buildup showed permeability at 150 md, skin at 0 and drawdown pressure at 290 psi.
Six weeks later, another pressure buildup was performed after bottomhole pressure dropped. This buildup showed permeability at 150 md, skin at 1 and drawdown pressure at 380 psi. The well was placed back into production at 7,000 b/d. This rate was sustained with little change in drawdown pressure across the completion. The sustained rate was a 4,000-b/d increase, and it came without the steep pretreatment decline.
The second well to show a rapid production decline was a frac-pack completion in a 5-in. liner. The production rate dropped from about 5,000 b/d of fluid to 2,000 b/d of fluid in an 8-month period. A total drawdown of some 1,700 psi with a skin greater than 20 was estimated. The bottomhole pressure and temperature gauges were not functional, complicating analysis.
Fines migration is rarely observed in a frac-pack completion. However, the success of the first treatment and the potential for fines migration indicated a matrix acidizing treatment similar to the one performed on the first well would be worth an attempt. The acidizing treatment would address damage from fines migration and from scale, if either were the cause.
What was learned
Post-treatment analysis of the Morpeth completion stimulations produced several conclusions that could have an overall beneficial effect on offshore development, particularly in deepwater fields with subsea wells serving floating production facilities.
First, it revealed sandstone acid stimulation treatments can be pumped successfully into a subsea completion without rig intervention, thus avoiding the operational risks such intervention can bring. Subsea flow lines and tree components were found able to withstand the corrosive exposure to acid treatments. As well, it was observed that careful analysis for formation mineralogy and compatibility testing can help ensure a successful acid treatment.
The bottom-line conclusion, however, was that the rigless acid treatment at Morpeth successfully removed damage and resulted in a significant production increase from at least one of the two wells.

Comments