Real-Time Monitoring and Control of Water Influx to a Horizontal Well Using Advanced Completion Equipped With Permanent Sensors
- I.D. Bryant (Schlumberger Well Services) | M.Y. Chen (Schlumberger-Doll Research) | B. Raghuraman (Schlumberger-Doll Research) | R. Schroeder (Schlumberger-Doll Research) | M. Supp (Schlumberger-Doll Research) | J. Navarro (Applied Radar Physics) | I. Raw (Schlumberger Well Completions & Productivity) | J. Smith (Barger Engineering) | M. Scaggs (Team Energy)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- December 2004
- Document Type
- Journal Paper
- 253 - 264
- 2004. Society of Petroleum Engineers
- 2.4.3 Sand/Solids Control, 1.6.7 Geosteering / Reservoir Navigation, 2.4.5 Gravel pack design & evaluation, 1.11 Drilling Fluids and Materials, 5.6.11 Reservoir monitoring with permanent sensors, 3.1.1 Beam and related pumping techniques, 5.5.2 Construction of Static Models, 2 Well Completion, 2.3.3 Flow Control Equipment, 3.3 Well & Reservoir Surveillance and Monitoring, 4.3.4 Scale, 5.6.4 Drillstem/Well Testing, 1.14 Casing and Cementing, 1.6 Drilling Operations, 4.5.7 Controls and Umbilicals, 5.1.2 Faults and Fracture Characterisation, 1.12.5 Real Time Data Transmission, 1.12.2 Logging While Drilling, 4.1.2 Separation and Treating, 4.1.5 Processing Equipment, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc)
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We have tested new technologies for real-time monitoring and control of water influx to horizontal wells with sand-control completions. In a thin oil column in Indiana, we drilled a horizontal well and completed it openhole with sand screens and a gravel pack. External casing packers (ECPs) subdivided the annulus into three zones. An electrical valve, which also records the annular and tubing pressure, controls inflow to each zone. Twenty-one centralizers acted as electrodes to form a resistivity array that spans the 694-ft-long completion. The well was also equipped with a fiber-optic distributed-temperature-sensing (FODTS) system. The well has been produced since November 2001 and provides real-time data that are shared across a geographically distributed network and used to optimize the production of oil from the well.
The data from the pressure sensors and the resistivity array have been jointly interpreted to dynamically update the static reservoir model, which was initially based on observations in offset vertical wells. The pressures recorded from the three electrical valves provide high-frequency data to characterize the near-well heterogeneity of the formation. These data are critical to computing an optimum production strategy. Zonal well tests, combined with interference testing between zones and wells, enable the estimation of communication between zones and the productivity index (PI) of each zone. The resistivity data enabled detection of water-saturation changes both in the formation and in the wellbore.
The completion technology tested in this well offers the potential to intelligently operate horizontal sand-control completions by combining real-time monitoring with downhole inflow control.
The production performance and ultimate recovery of horizontal wells are often less than predicted by fluid-flow simulations. Premature breakthrough of water or gas to the wellbore (caused by uneven influx along the well) is one reason for this disappointing performance. We tested a variety of sensing technologies that facilitate the intelligent operation of remotely operated valves to maximize well productivity and the ultimate recovery of oil. To achieve this test, we installed a completion in a very thin (originally 13 ft thick) oil column in the East Mount Vernon Unit of the Lamott Consolidated field, Posey County, Indiana (Fig. 1). This unit is operated by Team Energy and produces oil from the Tar Springs and Cypress sandstones. Most production is from the Mississippian Cypress sandstone reservoir. The previously existing vertical wells produce at a very high water cut (approximately 95%) because of the thin nature of the Cypress reservoir oil column.
Drilling and Logging
The Simpson No. 22 well was spudded in mid-June 2001. The 13 3/8-in. surface casing was set at 150 ft, and a deviated 8 1/2-in. pilot well was drilled to penetrate the Cypress sandstone close to the planned heel of the drainhole (Fig. 2). This established the depth of the formation and provided a suite of logging-while-drilling (LWD) logs across the reservoir interval (Fig. 3) that was used to provide a model to facilitate landing the build section of the well and geosteering within the reservoir. The logs also established that a higher-permeability layer, close to the middle of the original oil column, had been flooded with reinjected produced water. This finding necessitated targeting the horizontal section in the upper half of the reservoir interval. The well was plugged, and a 12-in. hole was drilled to the Cypress reservoir. We used a 3D Earth model, updated in real time using LWD logs, to successfully land this section of the well in the reservoir at 89° and drill the drainhole within a dipping 6 ft thick layer for 808 ft of oil-bearing reservoir.1 (The 9 5/8-in. casing was cemented in this section of the well at 3,162 ft. The 8 1/2-in. drainhole section was drilled with a polymer water-based drilling fluid to a total depth of 3,868 ft.) The LWD logs give important information on the attitude of the borehole with respect to the sedimentary layering in the reservoir, and they also provide a 3D caliper of the hole. We used this information to adjust the placement of the completion to set one of the inflatable ECPs across the shale that forms a local barrier to vertical communication within the reservoir.
Before we ran the completion, the horizontal drainhole was treated with an enzyme solution to break down the mudcake. The well was then circulated with diesel to provide a stable baseline measurement for the resistivity array. Viscous pills were used to kill the well for running the completion.
The upper and lower completion were run into the well between 24 and 30 July as a single-trip completion. Because we needed to install communication cables and splices, the completion was run only in daylight hours for the first 2 days. The production interval was isolated with a multiport production packer set in the 9 5/8-in. casing. The drainhole was segmented into three zones using ECPs designed with ports for the control lines and cables (Fig. 4). The production packer was set hydraulically through a work string by use of the gravel-pack service tool to isolate above and below the packer. The ECPs were set by use of hydraulic control lines connected directly to the inflate element and run to the surface, enabling direct monitoring of the ECP inflate pressures.
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