Modern reservoir management technology has been advancing steadily since the introduction in early 1970s of retrievable wireline-deployed memory tools that enabled producers and petroleum engineers to gather downhole pressure and temperature data during completion operations or from active wells.

Although these devices represented a significant technological step-change in their day, they were not without limitations. The added rig costs incurred to run retrievable wireline tools to obtain transient information about a producing reservoir was not an inexpensive proposition, an economic obstacle compounded by the need to suspend the well during testing. Over time, the increasing focus throughout the upstream oil and gas industry on more-difficult-to-produce reservoirs, at more remote locations and in more hostile downhole environments—plus the growing prevalence of secondary and tertiary recovery projects—pushed the risk-weighted cost of failure beyond acceptable limits.

Industry-wide efforts to control capital costs and manage operating spending, while accelerating production rates and improving ultimate recovery—despite evermore unforgiving circumstances—naturally have heightened the importance of true reservoir management, as well as the recognition that real-time reservoir pressure and temperature data is crucial to optimizing production operations.

Predictably, a wide range of retrievable, extended-test, and permanent downhole monitoring systems have been developed in an attempt to acquire a continuous stream of timely and reliable information about the dynamic forces of producing hydrocarbon reservoirs. Downhole monitoring systems also have evolved to keep pace with more demanding reservoir performance monitoring requirements, progressing from mechanical sensors to electronic, and more recently to optical sensors with applications in a wide range or oil, gas and hydrothermal wells.

Monitoring technologies of the future
Using fiber optic cable and sensors to quantify and monitor the performance of oil and gas reservoirs can provide several advantages over earlier mechanical and electronic downhole monitoring systems.

Perhaps foremost, fiber optic downhole measurement and monitoring assemblies are more robust, and usually are capable of withstanding corrosive subsurface environments and reservoir temperatures as great as 600 degrees Fahrenheit and pressures of up to 20,000 psi, while providing reservoir data that may be of exceptional accuracy and reliability. Fiber optic sensors can be effectively immune to electromagnetic interference and electrical component failure in adverse environments.

Many reservoir engineers and producers who have used fiber optic technology to monitor an oil and/or gas well believe it could be the permanent downhole monitoring technology of the future. Yet, despite the physical and interpretive limitations of mechanical and electronic monitoring technology, there are many familiar downhole monitoring products and services based on these older technological platforms that are capable of providing useful real-time and near-real-time data from producing wells.

Halliburton Energy Services has developed and presently offers a broad suite of reliable real-time, continuous, downhole permanent monitoring options, which can be integrated to help create premium permanent monitoring solutions for a wide spectrum of applications, including production, observation and injection wells. In addition to working to develop a fiber optic-based point-pressure monitoring system, the company also is working with industry partners on more long-term research aimed at developing new-age fiber optic sensor systems for measuring strain, flow rate, and phase holdup.

Halliburton also is working with partners to help develop electronic reservoir monitoring systems, based upon sensitive resonating quartz transducers, as well as more cost effective piezo-resistive technologies.

Downhole monitoring portfolio
One of the foremost fiber optic downhole monitoring systems in Halliburton's reservoir monitoring portfolio is a unique distributed temperature monitoring system.

The Halliburton Distributed Temperature System (DTS) represents a powerful breakthrough in downhole temperature-measurement technology, because it can allow a user to create a continuous real-time temperature profile along the entire well bore at intervals of as little as one meter. Changes in the wellbore temperature profile, in turn, can be interpreted to help determine the volume of gas and liquids each productive zone is contributing to total well output. Production actually may be allocated to individual geologic intervals based on distributed temperature data.

Optical fiber DTS can be deployed in a variety of ways to help in permanent, retrievable, extended or coiled tubing applications. The fiber assembly may be preinstalled in a capillary tube, which can then be run similarly to slickline for retrievable surveys or strapped to the completion or casing for extended-duration surveys.

The optical fiber can by pumped into position through a capillary tube inserted into the well as an attachment to casing or a completion assembly; or it can also be pumped down in the existing control lines. In an application involving multiple targeted zones or multiple packers, this process can help eliminate the need to splice the fiber optic cable during installation. Eliminating the splicing process can help save rig time during installation and can help deliver a cable with Improved light-loss characteristics. The DTS assembly also can be pushed into position via a process similar to the pumping option, then retrieved after the completion of the survey.

Halliburton also offers some of the latest in real-time pressure measurement technology for single or multiple points downhole, based on either proven capillary tube technology or a cost effective electronic platform that uses a piezo-resistive pressure transducer. The capillary tubing-based Pressure Transmission System (PTS) retains all electronics at the surface. Because no electronics or moving mechanisms are inserted downhole, PTS can be an extremely reliable and durable downhole monitoring technology; the oldest active PTS system was installed in 1982. PTS may be deployed in permanent or retrievable configurations.

Bottomhole pressure comparison between PTS and memory gauge. Time scale 46 days, pressure scale 3 psi, and each division is 0.5 psi. PTS temperature-corrected data delivers a comparable resolution to that of an electronic gauge.

Halliburton offers the piezo-resistive electronic permanent pressure monitoring system for low-cost applications requiring extremely high accuracy. Either pressure monitoring system could be recommended, depending upon the temperatures to be encountered in the targeted geologic interval.

Halliburton offers DTS completions with fiber optics terminating above or below the packer. When both the DTS and PTS are used, both lines can be encapsulated together or run individually. In the above-packer scenario, the fiber optic portion of the DTS is capped and terminates at the pressure chamber alongside the PTS capillary tube, which generally attaches via a high-pressure connection to the top of the pressure chamber. (The pressure chamber is only used when the PTS option is used.)

In below-packer applications, the DTS fiber optic control line tube passes through a turnaround sub—which keeps the control line on the outside of the tubing—and loops back up the tubing to terminate at a specified distance above the turnaround sub. The turnaround loop helps establish better accuracy for temperature gauge readings by providing two depth-identical temperature readings along the overlapping distance of the partial loop.

Downhole monitoring applications
The understanding of reservoir and wellbore dynamics enabled by the continuous, real-time pressure data and temperature profiles provided by Halliburton's portfolio of reservoir performance monitoring systems can help operators make sound, timely decisions that can help maximize oil and gas recovery, optimize fluid injection, assure completion integrity and improve the economics of an asset. Early warning of impending problems can enable timely adjustments or even significant changes to production or injection schemes or exploitation policies, or implementation of new drilling and workover programs. 

DTS installations in producer and injection wells allow accurate monitoring of fluid fronts.

Better understanding of reservoir performance can improve reservoir management programs by helping assess reservoir size, shape and compartmentalization; or by quantifying effects of depletion and pressure maintenance on the evolution of reservoir properties, such as permeability, productivity or injectivity indexes, mobility, and skin.

Continuous or time-lapse temperature or pressure data from each flowing zone can help allocate produced or injected fluids; help assess vertical sweep efficiency, breakthroughs or channeling, and undesirable fluid production; or help follow movements of injected fluid fronts including water, steam or gas, even in non-perforated zones. In secondary and tertiary recovery projects, inter-well or inter-zone communication can be ascertained to help assess inter-well or inter-layer reservoir properties, optimum well spacing, or maximum flow rates, as well as to validate geological and flow models.

Applied to wellbore performance issues, appropriate reservoir performance monitoring solutions can help ensure optimization of artificial lift, choke, and chemical-injection programs. It can help facilitate early detection of flow behind casing, completion leaks, underground blowouts and other completion integrity problems, helping to reduce or even eliminate an operator's exposure to such risks or hazards. As a result, the effective life of a completion can be extended, the production rate can be optimized, and the operator's exposure to intervention expenses and hazardous risks can be reduced or even possibly eliminated.

Clearly information like this is a valuable input not just for monitoring the particular well, but additionally for managing the entire reservoir.

Real-time and continuous DTS data also can be paired with Iwatch-RT™ software, the new version of Landmark's well-known WELLCAT software, to monitor completion integrity. Using DTS data, the software can calculate temperature profiles at relevant radii, stress profiles at completion components, and trapped pressures between tubulars and behind casing, helping to enable production and completion engineers to monitor effects of production or injection on the completion, to set hierarchical alarms, and to optimize the flow rate in real-time.

Taken together, Halliburton's real-time, data-driven, decision-support, reservoir performance monitoring solutions help enable users to better track and manage key dynamic reservoir parameters in producing wells, creating significant incremental value from well-performance and flow-assurance challenges, production allocation, well integrity, reservoir modeling and visualization, and reservoir management.

Existing Halliburton reservoir performance monitoring technology already is helping generate significant value in the field, helping to reduce capital investment and operating expenditures while accelerating production and maximizing ultimate recovery by helping to improve the certainty and predictability of extremely diverse oil and gas developments. That contribution is growing steadily as development and deployment continues of new fiber optic-based real-time downhole monitoring tools and services capable of helping to improve the reliability, predictability and profitability of oil and gas recovery from more extreme, difficult-to-produce reservoirs in more physically hostile subsurface depositional settings.