Sand Control

Sand control succeeds in high-rate, big-bore gas wells

Sand production is avoided offshore by employing expandable sand screens in horizontal holes that utilize big-bore casing. The result is high-rate output of gas and condensate.

David Munro, Woodside Energy Ltd., Perth, Australia

A two-well, subsea tieback of the high-rate Echo-Yodel gas-condensate field was successfully drilled and completed offshore Australia in 2001 by operator Woodside Petroleum. Rock strength measurements, combined with sand failure modeling, indicated the likelihood of sand production and associated output deferment.

Engineers selected expandable sand screens (ESSs) in horizontal holes as the preferred reservoir completion scheme. Frictional pressure drop at the high, planned off-take rates was a key factor. A big-bore casing scheme was selected, and considerable effort was put into developing and testing the sand control system with the supplier. This was backed by expertise from Woodside's JV partners.

Both wells have shown good productivity, with initial potentials of around 250 MMcfgd, each. Total off-take from the field is constrained by the system to 340 MMcfd of raw gas and 39,000 bcpd. A number of future subsea satellite tiebacks in the area have potential for applying ESSs. The technology is also of interest for possible remediation of existing wells, if they produce sand.

BACKGROUND

The Echo-Yodel field was discovered in 1988, in 135 m of water, 23 km west/ southwest of the Goodwyn “A” platform and 150 km offshore Dampier, Fig. 1. The reservoir contains roughly 400 Bcf of condensate-rich gas reserves, in extensive fluvial channel and bar sands of multi-Darcy permeability. The reservoir is at a vertical depth of 2,900 m, subsea, with pressures supported by an active aquifer. A number of future satellite tie-ins are envisioned (Keast, Dockrell, Dixon, Wilcox, Rankin-Sculptor), Fig. 2.

Fig. 1. Echo-Yodel field is on the North West Shelf, near the Goodwyn “A” platform.

Fig. 2. The Echo-Yodel area, satellite tie-back schematic can accommodate development of several additional fields.

Studies concluded that this field's major reservoir, the Lower E sand, could be developed optimally with two subsea wells, tied back to the Goodwyn platform via a 12-in. pipeline. Production came onstream in late 2001, with an expected field life of four to five years.

This article summarizes the sand control aspects of the wells' conceptual design, construction and subsequent performance. It reviews the potential further applications opened up by ESSs in the area.

REQUIREMENTS FOR SAND CONTROL

Core measurements of thick-walled cylinder (TWC) and unconfined compressive strength (UCS) indicated weak, loosely consolidated rock to low-strength, consolidated rock. At about 230 bar TWC, the minimum rock strength was among the weakest seen across the North West Shelf's producing fields, with coarse-grained sands typically the weakest. However, attempts to correlate rock strength indicators to log and core parameters yielded a poor fit. Depth-corrected and facies-filtered data gave regression coefficients in the range of 0.24 – 0.58, with porosity and permeability giving the better correlations, Fig. 3.

Fig. 3. TWC rock strength correlation indicated weak strength in the Echo-Yodel area.

Although some uncertainty was recognized, sand failure predictions suggested that a horizontal well would have a greater-than-50% likelihood of experiencing transient sand failure on start-up, and might experience massive transient or catastrophic failure later in field life, Fig. 4.

Fig. 4. Prediction of initial sand failure mandated the installation of sand control equipment.

Although the prediction methodology used appears to give conservative results in offset fields, the sand production risk was concluded to be significant. The consequences of sand production, both for the Echo-Yodel satellite and the remainder of the Goodwyn system, would be considerable in terms of erosion potential, reduced operability and production deferment for remedial measures. Cost-risk analysis, therefore, concluded that up-front, sand control installation would be required for an Echo-Yodel horizontal well development.

SELECTION OF SAND CONTROL TECHNIQUE

The performance of alternative sand control or exclusion techniques was reviewed. For the high-productivity wells planned, frictional pressure drop along the reservoir section was an important consideration. Representative pressure drops for a base case horizontal length and production rate with an 8-1/2-in. hole through targeted formations are illustrated below, Fig. 5.

Fig. 5. Representative flow diameters and pressure drops for the high-production wells planned.

The initial sand control recommendation (May 2000) was to apply horizontal, openhole gravel packing (HOHGP) with water-packing as the base case, and a watching brief would be maintained on the emerging ESS alternative. Stand-alone screens were rejected, due to the risk of plugging and subsequent erosion.

HOHGP advantages were seen as (relatively) proven technology that was tolerant to over-gauge hole. Concerns were a lack of Australian operational experience with the technique (including perceived uncertainty in the robustness of the water-packing fluid system under Echo-Yodel conditions), an intolerance to under-gauge hole and the well performance implications of a reduced flow diameter across the reservoir. ESSs offered the possibility of maximizing flow diameter with simpler installation logistics. This technology was recognized as being intolerant of out-of-gauge hole, less resistant to collapse and requiring the climbing of a new learning curve.

Growing industry experience with ESSs, backed by strong technology support from JV partners Shell and BP, led to ESSs being promoted as the favored option. Considerable effort was put into development and testing of the 5-1/2-in., compliant rotary expansion system (CRES) with Weatherford, to assure full expansion under wellbore conditions, Fig. 6.

Fig. 6. CRES tool and 5-1/2-in. ESS expansion.

ESS SYSTEM DESIGN

To maximize deliverability, the well design included a big-bore casing and completion scheme. An 8-1/2-in. horizontal hole was planned through the reservoir in combination with 5-1/2-in. ESS's. Production would be via a 9-5/8-by-7-in. completion to a 7-by-5-in., horizontal subsea tree, Fig. 7. Individual well capacities of about 200 MMcfgd were expected.

Fig. 7. Schematic for an Echo-Yodel big-bore well.

Inflow modeling indicated little deliverability benefit beyond a horizontal completion length of 200 m in the most likely case. The first well targeted the LE3 sand only, and therefore could be limited to about 200 m of horizontal length. However, the second well targeted both the LE3 and LE1 sands. This required a sub-horizontal well trajectory of 1,300 m, and traversal of the LE2 shale, Fig. 8.

Fig. 8. Reservoir cross-section for the LE1 and LE3 sands.

Engineers recognized that a slightly downward trajectory that follows stratigraphy at the reservoir's top might create a hydrostatic head of completion fluid at the well's toe. In turn, this might prevent filter cake pop-off at the drawdowns imposed at the heel. They concluded that the need for maximizing ultimate recovery was overriding and that the toe might clean up later, if a differential pressure gradient was established around the well (e.g., between LE1 and LE3).

Net to gross within the LE1 and LE3 sands was expected to be greater than 90%. To limit torque and drag, the trajectory design kept dogleg severity at 3.5°/30 m. Wells were planned for clean-up via a rig test package, to a rate of about 80 MMcfgd, before commissioning the pipeline and final clean-up to the platform.

Drill-in fluid. Alternative drill-in fluid systems considered were water-based, saturated sized salt (WBM), oil-based synthetic mud (OBM) and ester-based mud (EBM). EBM was favored, in line with Woodside's standard approach to high-angle or extended-reach wells. Testing was conducted to allow a thin, robust filter cake, minimal fluid loss, stabilized shales, return permeability > 70% and lift-off pressure < 10 psi. Based on pore throat size distributions, the minimum, solid particle diameter to be used was 26 µm.

Bridging solids were initially designed at 50 lb/bbl, but this figure was reduced to 10 lb/bbl following successful deployment by another operator without such additives. Quality control of the mud was assured by providing a flow-through test apparatus on the rig.

Filter size. From corings, 22 particle size distributions were obtained. Finer sands had a d 50 of 220 µm, increasing to 970 µm for coarser sands. The main LE3 target had a uniformity coefficient (d₄₀/d₉₀) in the range of 1.7 – 6.8, while the LE1 target was measured at 2.3 – 4.0. Sands are considered well sorted with a coefficient below 3 and poorly sorted above 7. Fines (<44 µm) comprised less than 5%, by weight.

The selected filter size of 270 µm was the coarsest Petroweave filter medium available. It equated to about d₄₀ of the finer sands and d 90 of the overall sand distribution, Fig. 9.

Fig. 9. LE3 unit particle size distribution.

Mechanical strength. Torque and drag analyses indicated that running 1,300 m of 5-1/2-in. ESS would lead to compressive loads on the order of 50% of their design rating of about 120,000 lb. Owing to the strong aquifer support, compaction forces on the screens over their life cycles were not expected to approach the point load compression limitation of about 2,500 psi for uncentralized, 8.75-in. OD ESS in the LE2 shale.

Development testing indicated that the ESS would have to be expanded with a minimum fixed-cone size of 6.5 in. before the CRES tool could be run.

INSTALLATION

In Yodel 3, 237 m of 5-in. ESS were run. Running weight increased significantly at a 60° hole angle, around 200 m above the 9-5/8 -in. shoe. Tight spots with set-down weights up to 45,000 lb were required over the first 20 m of open hole, and further running into the hole was not possible. The openhole sonic did not indicate under-gauge hole log at these depths. The hole size was measured at 8.5 in. to 9.0 in. throughout, apart from a 9.5-in. washout in 35 m of shale interval toward the heel. The ESS was pulled and re-run following a wiper trip, with a number of joints rejected, due to damage to the connectors on break-out and damage to the rubber of an expandable isolation sleeve.

TD was reached successfully by the second ESS run. Two initial attempts with a 6.625-in., fixed-cone run were unable to pass a point 15 m into the open hole. This was followed by a successful 6.00-in. run, an unsuccessful 6.625-in. attempt, and then a successful, 6.5-in. fixed-cone run to TD. Final expansion to 8-1/2-in. hole was achieved with a single CRES run. Overall, expansion took 9.5 days.

Difficulties in running, then expanding the screens appeared to be due to debris in the wellbore, reinforcing the necessity of achieving excellent hole cleaning. Following expansion, the drill-in fluid was displaced to 1.15 SG KCl brine. Minimal losses were experienced, indicating that the filter cake remained in good condition.

In Yodel 4, LE3 sands were encountered as prognosed, but with a significantly more extensive LE2 shale than expected. This led to hole stability problems toward the toe, and progress was not possible beyond a 1,356-m horizontal section. The ESS length was limited to 444 m to secure well deliverability. The sonic caliper indicated a hole size around 9.1 in. over the heel section, with no tight spots or washouts.

The 5-1/2-in. screens were run successfully to depth on the first attempt, with significantly less resistance than encountered on Yodel 3. One 6.625-in., fixed-cone run and one subsequent CRES run were used to expand the screens to 8.5 in., OD, over three days. A blank nose and rubber-coated, expandable isolation sleeve were set at the well's toe, to isolate drill-in fluids that remained in the sump.

Subsequent displacement to brine again resulted in minimal losses.

PERFORMANCE

Both wells were cleaned up, yielding potential, per-well productivities of around 250 MMcfgd, when flowed individually. Total off-take from the field is constrained by the system to 340 MMcfg of raw gas and 39,000 bcpd. Even with big-bore completions, the sands' productivity is such that the wells remain tubing-constrained, with drawdowns on the order of 30 psi at 200 MMcfgd, Fig. 10. As such, well performance is relatively insensitive to skin.

Fig. 10. Vertical lift and inflow curves.

Transient pressure analysis is difficult, given the combination of high transmissibility, wellbore storage, nearby constant pressure, and no flow boundaries and observed condensate drop-out effects. A tentative interpretation gives a completion skin in the range of 0 to +10, with a most likely value of +3.5. There has been some decline in well potential over the first six months of production, but this is in line with simulations of reservoir pressure decline. No sand production has been observed on surface Fluenta meters.

FUTURE APPLICATIONS

The Echo-Yodel project successfully demonstrated the potential for using ESSs in high-rate, horizontal gas wells. Analog applications exist in a number of future satellite tiebacks in the area, should sand control be required. Some of these applications will be subjected to significantly higher depletion than seen on Echo-Yodel, presenting challenges for the screens' mechanical collapse resistance.

ESS technology is also of interest, if remedial sand control proves necessary in existing Goodwyn area wells – for example, under blowdown in combination with water breakthrough. One option would be to deploy screens through tubing and expand them against perforated cased hole, provided both productivity and erosion resistance are preserved, and zonal selectivity remains possible. Description of the successful deployment of such a system will have to await a future date.

CONCLUSIONS AND RECOMMENDATIONS

After more than two years of production, the wells continue to produce sand-free, in line with expectations, with no indications of plugging. Accordingly, a number of recommendations have been made for future installations:

First, high importance should be placed on clean, stable hole conditions. Personnel should also pay close attention to drill-in fluid design and selection, to ensure good drill-in fluid conditioning on-site using a flow-through test kit.

Similarly, close attention should be paid to working with the ESS provider, allowing enough time for planning and testing. Crews should also control the build rate and minimize dogleg severity in the production interval. Furthermore, it is important to anticipate friction factors on the order of 0.5 with ESS in open hole, and to ensure that wellsite personnel have a good working knowledge of torque and drag.

Additional considerations include keeping a range of back-up expansion tools on site; locating the crossover from solid pipe to ESS in the liner, rather than in the open hole; and allowing for a rejection rate if the ESS has to be recovered and re-run. It is also essential to continue engineering development efforts to achieve a robust, single-trip expansion system.

The Echo-Yodel success opens the possibility that ESSs can be employed in other satellite tie-backs in the area, should likelihood/ consequence analysis support it. The learning curves from other operators in deploying ESSs would also form part of such assessments. Some applications would experience significantly greater depletion than the rate expected on Echo-Yodel, and mechanical collapse resistance is perceived as an issue.

Expandable screens are also of interest for remediation of existing wells, should they produce sand. This presents a number of challenges, including the deployment and expansion, plus securing sufficient sand-free inflow without exposure to erosion or plugging. 

ACKNOWLEDGMENTS

This article is based on a paper presented at IQPC Sand Control and Management: A Holistic Approach Conference, Sept. 24 – 25, 2002. The author thanks Woodside and its North West Shelf joint venture partners for their permission to publish this article. The work reported was carried out by Woodside's subsurface and well engineering project teams, strongly supported by specialists from BP and Shell's sand control groups, Weatherford and Advanced Well Technologies.