In 1999, an oilfield experiment was initiated to test the application of electrical measurement technologies to permanent reservoir monitoring. The principal objective of the experiment was to demonstrate the feasibility of monitoring water movement between an injection and an observation well. This paper describes the interpretation of the data provided by the resistivity arrays and discusses the data quality and reliability of the measurements.Two wells were drilled into the Mansfield sandstone reservoir in Indiana, U.S.A. The D-8 injector well was located in the center of four development wells. The OB-1 monitoring well was offset 233 ft to the southwest in a location midway between the D-8 injector and the No. 3 production well. The injector was instrumented with a 16-electrode resistivity array that was run on the outside of insulated casing and cemented into the annulus of the well. A similar array was cemented into the annulus of the monitoring well.In March 1999, the D-8 well was perforated and acidized. A surface gauge was used to monitor injection rates and pressures. Initially, injection proceeded at a rate of approximately 20 B/D, increasing to 90 B/D after fracture stimulation. The D-8 array records responses to wellbore operations and injection. It clearly distinguishes the movement of the waterfront in different zones. The OB-1 electrical array clearly indicates early water breakthrough by means of an induced fracture. The data show good signal-to-noise ratio and high reciprocity.The experiment has demonstrated the viability of using permanently installed resistivity arrays to monitor the movement of oil/ water contacts and salinity fronts that are some tens of feet away from the wellbore. Results demonstrate the feasibility of using such arrays to monitor oil/water contact movements remote from injection, monitoring, and production wells.
We describe here a test of a new technology for successful drilling of horizontal wells in thin oil columns. We constructed a three-dimensional (3D) earth model of the overburden and of the target reservoir layers on the basis of predrilling data and updated this model in real time on the basis of logging-while-drilling (LWD) measurements transferred to remote locations using the World Wide Web. This strategy allowed us to check and update the planned drilling trajectory continuously with all the information available at any given time. We used uncertainties in the depth of markers observed in a number of offset vertical wells to determine the uncertainty in the thickness of layers in the earth model. This 3D model comprised best estimates of the thicknesses and a covariance matrix that quantified their initial uncertainties. We then drilled a pilot well. Trajectory data, LWD logs, and resistivity images from downhole measurement-while-drilling (MWD) and LWD tools were transmitted in real time from the Simpson No. 22 drill site in Indiana to a prototype application running in Connecticut. As we acquired new measurements in the pilot well, we compared log curves predicted by the model to the measured logs. Our prototype allowed an interpreter to update the location of markers as the well was drilled; an update of the entire 3D earth model and its uncertainty was then automatically computed in near-real time. Quantified uncertainties are key in this stage to ensure that the model update is in agreement with all the data considered previously. This procedure was repeated while drilling the horizontal drain hole, which was successfully steered within a dipping 6-ft-thick layer for 808 ft. Our prototype also allowed for remote collaboration: 3D model updates, LWD data, and resistivity images were available to collaborators who were connected to the network and simultaneously ran copies of the prototype at additional locations. In particular, the remote availability of real-time resistivity images was key to the successful well placement, as these images show how the well trajectory follows the layering. Remote collaboration means that drilling decisions can be made collaboratively by a globally distributed team in a secure network environment. This can be a key capability for geosteering, especially in remote locations or when staffing is constrained. Introduction High-angle and horizontal wells offer the opportunity to tap previously unrecoverable hydrocarbons that occur in thin columns. To achieve this objective it is often necessary to precisely position the well with respect to fluid contacts and/or sedimentary layers. Frequently there is uncertainty in the disposition of these features, so that the target cannot be geometrically defined and real-time data on the position of the features are required to geosteer the well.1 We wished to test the application of novel completion technologies to drain oil from a very thin (originally 13-ft-thick) oil column in the Mount Vernon Unit of the Lamott Consolidated field, Posey County, Indiana (Fig. 1). To do this, we needed to drill an 808-ft-long horizontal well in oil-bearing sandstone.2 The East Mount Vernon 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 (~ 95%) because of the thin nature of the Cypress reservoir oil-column. The Simpson No. 22 well was drilled first as a deviated pilot well, to penetrate the Cypress sandstone close to the planned heel of the horizontal section, and subsequently as a smooth build section (< 4°/100 ft) leading to a horizontal section in the Cypress reservoir (Fig. 2).
In 1999 an oilfield experiment was initiated to test the application of electrical measurement technologies to permanent reservoir monitoring. The principal objective of the experiment was to demonstrate the feasibility of monitoring water movement between an injection and observation well. This paper describes the utility of the data provided by the resistivity arrays and discusses data quality and reliability of the measurements. Two wells were drilled into the Mansfield sandstone reservoir in Indiana. The D-8 injector well was located in the center of four development wells. The OB-1 monitoring well was offset 233 ft to the southwest in a location midway between the D-8 injector and the No. 3 production well. The injector was instrumented with a 16-electrode resistivity array that was run on the outside of insulated casing and cemented into the annulus of the well. A similar array was cemented into the annulus of the monitoring well. In March, the D-8 well was perforated and acidized. A surface gauge was used to monitor injection rates and pressures. Initially, injection proceeded at a rate of about 20 B/D, increasing to 100 B/D after fracture stimulation. The D-8 array records responses to perforation, acidization, swabbing, fracturing, and injection. It clearly distinguishes the movement of the waterfront in different zones. The data show good signal-to-noise ratio and high reciprocity. The OB-1 electrical array clearly indicates early water breakthrough via an induced fracture. The arrays show no degradation of signal over the 17-month duration of the experiment. The experiment has demonstrated the viability of using permanently installed resistivity arrays to monitor movement of oil-water contacts that are some tens of feet away from the wellbore. Results demonstrate the feasibility of using such arrays to monitor oil-water contact movements remote from injection, monitoring, and production wells. Introduction The industry drive toward using intelligent wells to improve recovery efficiency will require continuous monitoring and optimization of reservoir drainage. Currently, commercial monitoring is through sensors that measure flow in the wellbore and permanent borehole pressure gauges. These sensors allow for reactive reservoir management: opening or closing production zones as a response to breakthrough of unwanted fluids into the wellbore. Proactive reservoir management is possible if we are able to detect the advance of unwanted fluids in the formation, prior to their breakthrough into the production stream. We have conducted an oilfield experiment to demonstrate that sensors can be deployed and used to monitor fluid movement remote from the wellbore.1 As this was the primary objective of the experiment, emphasis was placed on demonstrating the feasibility and utility of such measurements, rather than on testing a commercially viable deployment scheme.
Summary 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. Introduction 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. Well Completion 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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