As operators seek to increase their recovery factor, the industry has to find ways to meet the technical challenges associated with the push to maintain or increase production in mature fields and unfavorable environments.

In a move to answer this need, Tendeka was formed to provide a diverse choice of technologies to optimize each well’s productivity.

The company is combining field proven technologies to bring significant benefits to operators, including optimizing production, extending field life, and providing accurate and real-time well surveillance.

Enhancing horizontal well performance

FloTech’s ICD completion with swellable packer (Images courtesy of Tendeka)

In early 2008, a major Middle East operator contracted FloTech, a Tendeka company, to provide a passive inflow control device (ICD) completion string after a horizontal well with total depth of more than 13,000 ft (3,962 m) experienced a rapid production decline and increased water cut.

A PLT survey was carried out that showed both a flowing and a shut-in pass. During the shut-in pass, considerable downward cross-flow was evident due to the differential reservoir pressure along the horizontal section, which recorded at 200 psi from heel to toe. Coiled tubing could not reach the entire lateral length, so only one “thief” zone could be identified. The production log measured the oil rate during flow conditions at 4,000 b/d with a ±30% water cut and showed that only the first 10% of the horizontal section was contributing to production.

This reservoir’s significant pressure gradient and reduced well performance led to a decision to deploy a passive ICD completion string into the existing horizontal lateral. The objectives were to enhance production contribution from the entire 5,200-ft (1,585-m) lateral and overcome the unfavorable heel-to-toe differential pressure, reducing the downward cross-flow and minimizing water influx to prolong the well life.

Numerous wellbore hydraulic simulation runs were carried out to determine the number of ICD units and segments required. Sensitivity runs with various fluid rates ensured the ICD completion would function effectively within the preferred flow range and maintain positive contribution across the entire lateral. An optimum design rate was selected at 8,000 b/d.

Swellable packers were used to create the different compartments and segments across the lateral. The well was worked over and re-completed with 22 ICDs and seven swellable packers without having to deepen or sidetrack the well. Following the workover, surface well test data indicated stable oil production with reduced water cut (<10%). The completion was intensively tested at both target and elevated rates to ascertain its performance and coning tendency.

To confirm the inflow profile along the length of the of the ICD completion, a PLT survey was conducted in mid-2008. Shut-in and three flowing passes were run to assess the ICD completion string performance at different rates, thus determining the optimum rate. The cross flow, evident in the openhole log, was eliminated while achieving contribution from the entire lateral. The actual profile compared favorably with original completion design at the same rate.

Providing a complementary technology solution allowed water production to be greatly reduced, leading to an extended field life. The oil production rate doubled, indicating significantly improved well performance.

Monitoring MRC wells

Tendeka’s DTS captured data during the installation.

The benefits of combining technologies was proven again when Tendeka deployed its advanced digital flow profiling (DFP) system for a major Middle East operator. This implementation required a highly accurate permanent production monitoring solution for the company’s maximum reservoir contact (MRC) wells.

The DFP system comprises fiber-optic distributed temperature sensing (DTS) technology with near real-time data interpretation software. DFP was integrated with a three-zone intelligent well completion system incorporating hydraulic interval control valves (ICV), a hydraulic production packer, a hydraulic annular isolation packer, and an electronic permanent downhole monitoring system (EPDMS).

The intelligent well and DTS system was deployed inside a 9 5/8-in. upper casing string and lower 7-in. liner with pre-milled lateral windows across two openhole laterals. Two of the ICVs were placed across the openhole laterals to control production, with the third ICV placed on the motherbore to control production from the openhole section below the 7-in. liner. The DTS system was deployed to the toe of the completion string to monitor flow performance.

In-line optical splices allowed the fiber-optic cable to pass through the annular isolation packers. Testable splice assemblies were used to ensure system integrity and longevity pressure. These incorporated fiber-handling mechanisms to allow rapid assembly on the rig floor. A double-ended DTS configuration allowed automatic temperature measurement calibration. This configuration ensured high measurement accuracy and repeatability. During installation, 29,000 ft (8,839 m) of fiber optics monitored the system.

The fiber-optic cable passed through the tubing hanger and terminated at a 10,000-psi rated outlet connected to a local junction box at the wellhead.

The DTS system used a fixed fiber allowing continuous monitoring during installation. This provided a high degree of confidence in the system operation during deployment. It also allowed completion equipment to be monitored during operational tests before the production packer was set.

Monitoring operational tests was especially relevant to the ICVs as complex completions — such as the MRC wells — require a large number of control lines to be run with the completion. Before the production packer was set, the ICVs were function tested and the temperature profile monitored on the DTS system. The ICV was cycled open and fluid injected into the tubing from surface. The cooler fluid within the tubing string was able to move down and out through the ICV resulting in cooling. Members of the rig crew were therefore highly confident that they were operating the correct ICV.

Following the installation, the well was shut in and the temperature profile monitored intermittently prior to the well startup.

The well was production tested six weeks after installation, with the DTS system monitoring initial production. A restricted choke recorded an oil production rate of 15,000 b/d with no water cut. Prior to production, downhole temperatures were close to geothermal. Once production began and the upper well bore began to heat up, temperature profiles were acquired every minute. The monitoring system can detect temperature deviations resulting from the inflow in the motherbore as well as inflow at each of the laterals. A temperature reduction of about (32°F or 1°C) occurred in the motherbore during startup. After two hours of production, a temperature snapshot was obtained and placed alongside the completion. Inflow at the laterals were easily identified due to the temperature increase relative to the cooler fluid produced from the motherbore. Although only a limited clean-up period was monitored, future testing will be combined with a variation of the ICV positions to assess the impact in lateral rates.

Initial testing has demonstrated the value of monitoring the initial transient behavior where lateral contribution and rates of change could be detected.

DFP provided a cost-effective alternative to PLT interventions in the complex MRC well delivering valuable real-time data during installation to confirm the operation of completion equipment and circulation of wellbore fluids.

The in-well cables, downhole splices, wellhead outlet, and surface hardware required for DFP can feasibly be integrated in a complex MRC well. No significant delays or non-productive time related to the monitoring system were observed during the installation, and initial data have proven the required resolution of 30.9°F (0.01°C) has been achieved despite the fiber length and three in-well cable splices.