Developing heavy and viscous oils from deepwater plays is one of the newest frontiers for the industry. One of the more interesting challenges when producing heavy crude to surface in these reservoirs is the way long horizontal and/or multilateral wells are often used to maximize drainage.  This is especially true in cold and deep water wells producing viscous oil to surface from unconsolidated formations.

With analysts predicting that today’s high oil prices will be with us for the next year (WEC/WEA report Nov 2005), the time is right to exploit these reserves. However, cost efficiency and risk reduction are key in this environment and it requires special processes and advanced technologies to bring these reserves on line in budget and to plan. Given this context, efficient testing and reservoir characterization procedures assume increasing importance to meet bottom line production targets.

To achieve testing objectives for deepwater, heavy oil reservoirs requires a detailed, integrated testing-design process. To design and select the most effective production lifting and surface flow equipment and workflow requires a thorough reservoir understanding. Obtaining a thorough reservoir understanding also enables valid procedures to be designed for safe, environmentally compliant effluent disposal. This is only possible with accurate downhole data; therefore, suitability of the downhole and surface well testing equipment and processes relative to the heavy and viscous fluids to be tested must be considered.

The integrated appraisal process

Thorough reservoir characterization is not a single-phase process. It is in fact a multidisciplinary, interdepartmental process that continues for the life of a field. It begins in the exploratory stage with geological and geophysical assessments, including testing, and continues on through the appraisal, development and production stages of a field. Such essential measurements and simulations throughout the reservoir life cycle help to optimize all the equipment and processes involved.

Not too long ago, these thorough field characterizations were only employed during a field’s more advanced stages. Now, numerical reservoir simulation models are used to analyze exploratory tests and better position wells in reservoirs by applying so-called real-time simulation.

 Simulations enable all members of a multidisciplinary asset team to analyze uncertainties related to various development scenarios for a given well or field, giving priority to its technical and economic performance. They also may be applied to improve petrophysical facies characterization or eliminate uncertainties in the areal distribution of formation properties. In today’s market, with increasing pressure on operators to deliver assets online, within budget, and to schedule, there are a multitude of  ways to apply highly sophisticated, integrated reservoir characterization tools  to attain true reservoir insight and optimal development planning.

Heavy oil presents more challenging questions than conventional crude reserves. Capital expenditure for completions engineering is of critical concern, especially when working offshore. In this regard, having a versatile, integrated reservoir characterization process becomes paramount to success. Because every heavy oil reservoir is different, and there are even differences within a reservoir, understanding fluid behavior is key. More knowledge is required than the usual characterization of fluid and rock under reservoir conditions, including the heterogeneities and anisotropies involved.  This knowledge is vital to predict lifting performance, with or without help from bottomhole injection to reduce crude viscosities. Moreover, this information provides the opportunity to accurately assess the fluid/rock mechanisms that can impact the economics of various development options, thus improving the efficiency of the operation total.

For example, heavy oil reserves in cold waters can be produced using a number of production mechanisms, such as foaming, which disperses small gas bubbles in a heavy oil mixture to reduce viscosity. Whenever heavy oils exist in unconsolidated sands, excellent production rates can be achieved by creating a network of stable tunnels, called wormholes, which act like fractures or effective production pathways. Given multiple production options, the testing challenge becomes planning tests that will provide data to adequately characterize and predict the outcomes of each mechanism.

An example of the components used in an integrated heavy oil service is illustrated in Fig. 1. A criteria flow analysis of a multicomponent system such as this would involve not only the separate performances of the selected key technologies but also the optimization of the complete interrelated system. A system analysis would consider the conditions of multiple parts, including lifting, sampling and well testing.

Fig. 1. The criteria flow analysis shown for a heavy oil integrated service solution involves not only the performance of each of the selected technologies, but also the analysis and optimization of the whole interrelated system. (click for full size image)

Designing and optimizing heavy oil tests

The preferred way to design and optimize heavy oil well tests begins by using petrophysical and fluid characterization logs from the well to be tested, in addition to prior information from correlated fields or wells, as the basis for recommending an appropriate lifting-testing-disposal configuration (Fig. 2).

Fig. 2. The preferred design and optimization process for a heavy oil test begins by using the petrophysical and fluid characterization logs from the well to be tested, as well as prior information from correlated fields or wells, as the basis for recommending an appropriate lifting-testing-disposal configuration. (click for full size image)

 A preliminary well productivity estimate is made from open-hole logs, including wireline formation testing (WFT) data. Fluid characterization data comes from pressure-volume-temperature (PVT) analyses done onsite or near the rig by a mobile lab using open-hole logging samples, whenever feasible. Whenever a wellsite PVT analysis is not possible, a heavy oil database is used to infer fluid properties and behavior through correlation.

Given fluid properties and a preliminary productivity index (PI), pump performance is estimated and the discharge pressure and temperature, as well as the wellhead pressure (WHP) are computed. This enables the pump and samplers to be placed in the best position in the drillstem test string.

The use of downhole gauges during the operation to monitor drawdown, intake and discharge pressure, as well as WHP means PI, pump performance and fluid parameters can be interpreted in real-time, and therefore decisions can be made proactively to optimize production. Vertical/horizontal multiphase flow correlation matching provides a real-time lifting diagnostic, and optimization and consequent set-up of appropriated flow conditions. This supports decisions regarding sampling time, separation and other specific evaluation objectives.

Ensuring the safety and diagnosing the performance of various equipment configurations is an important part of heavy oil testing. A particular configuration can be verified and adjusted, as needed, during the operation using real-time data readings.

The testing procedure

The appraisal planning process, or more specifically the planning of conventional well testing operations, can be split into two parts

1)      the drillstem test (DST) string, including the artificial lifting system used, and

2)      the surface well testing plant—with strict controls and safety standards being observed at all levels.

In other words, planning should ensure that the oil reaches the surface and that the plant can process and discard or accumulate the effluents in a safe and environmentally correct manner. This must be done without losing sight of the reason for the operation, that is, the main objectives of formation appraisal.

As mentioned, the downhole well testing, production lifting and SWT (surface well testing) components used in heavy oil operations are similar to those used in conventional oil production, with some special modifications. A typical heavy oil testing/lifting string (Fig. 3) is usually composed of a wellhead, drillpipe, subsea test tree (SSTT), blowout preventer (BOP) can, gauges carrier, downhole test valve, sampling carrier and tubing-mounted electric submersible pump (ESP).

Fig. 3. A typical heavy oil testing/lifting string is composed of the multiple elements shown. (click for full size image)

At the surface, the well testing plant includes, among other components, a surface flowhead, multiphase flow meter, heater, separator, tanks, transfer pumps, and effluent burner. To optimize the testing phase, consideration must be given to the volume of drilling fluid lost to the formation while drilling, the ESP’s range of operation, and the flow rate desired while testing. Also, storage tank volume and heating capacity must be factored in to allow for appropriate burning or disposal. This is especially important given the difficulty associated with burns, and tank measurement, when water emulsion is present, and given the unstable sea and wind conditions offshore.

Experience has shown that a mobile multiphase flowmeter is mandatory equipment in these operations. When lower surface pressure causes low gas content in the oilstream, multiphase metering accomplishes continuous flow rate measurement from the time the well is opened. The multiphase meter used in conjunction with the artificial lift diagnostic process enables ESP optimization during operations. High frequency monitoring of the separation process in real-time: oil, gas, water vessel level, densities, flow rates, resistivities, oil content in the water line, as well as the aperture of the oil, water and gas line control valves helps to identify variations in flow before issues occur.

Recommendations

Heavy and viscous oil in deepwater wells present a unique well testing challenge requiring a change in mind-set and focused expertise. For ultimate testing operation performance, it is important to obtain maximum, accurate and in-time information from an integrated investigative process, which involves formation evaluation, fluid properties characterization, lifting and surface flow assurance variables. For each well, early data gathering and analysis, including the analysis of open-hole fluid samples, should be available in time to assist with the design and optimization of a well testing strategy and execution program. Bottom line, the thoroughness of the rock and fluid characterizations achieved impacts the accuracy of the subsequent reservoir appraisal—an essential step to achieving today’s reservoir optimization goals.