Safely testing deepwater wells requires purpose-built technology and a good deal of experience.

By improving the safety and reducing the costs of deepwater well tests, several key technologies are improving operators' comfort with drawing samples and gathering production and pressure data from wells drilled in waters as deep as 10,000ft (3,050m). Schlumberger has conducted six such tests recently, including one offshore Congo Republic and another offshore Nigeria. The technology suite that contributed to the success of these tests included a full-bore intelligent downhole tester valve, a pressure-actuated sample carrier, a subsea test tree controlled by a deepsea electrohydraulic system that allows for quick disconnect, a hydraulic retainer valve and a riser sealing mandrel.
New discoveries
Early this year, Texaco reported the Agbami-2 discovery well drilled in Block 216 offshore Nigeria "surpassed expectations" and was among the largest finds to date in deepwater West Africa.
Meanwhile, in May TotalFinaElf announced a new oil discovery on the Mer Tres Profonde Sud permit offshore Congo Republic. The Andromede Marine-1 well set a record for the Congo by reaching a water depth of 6,211ft (1,894m). It tested high-grade oil at 7,000 b/d.
Testing suite
Each of these discoveries was successfully tested in a safe, efficient manner from a floating drilling vessel by using a combination of technologies.
Subsea test tree. The subsea test tree plays the primary subsea safety role when included in the testing mix. In the case of an emergency, the tree enables a well to be shut in so the top section of the landing string and marine riser package can be disconnected from the main testing string and the subsea blowout preventer (BOP).
Test tree control system. The deepsea electrohydraulic system is used to remotely control the test tree in waters up to 10,000ft (3,050m) deep. It can close and unlatch the test tree in 10 seconds regardless of water depth. It is rated to 15,000 psi working pressure and H2S service.
Riser retainer valve. The retainer valve (RETV-D) prevents the release of hydrocarbons into the riser should an emergency disconnect be required during testing. It is controlled hydraulically in sequence with the subsea test tree. An integral bleed-off valve vents the trapped pressure between the retainer valve and the subsea test tree to the riser before an unlatching procedure.
Riser sealing mandrel. The riser sealing mandrel is used to safely control and divert gas that enters the riser during testing. It is at the diverter BOP level - the diverter BOP is closed on it - below the rig floor. It is an added safety device used to meet hazardous operations requirements during deepwater testing. Special rubber hose sealing elements secure all umbilicals.
Bottomhole sample carrier. The Scar pressure-actuated sample carrier is a 7¾in. OD carrier that can house up to six PVT (single-phase oil) samplers for a maximum sample volume of 3.6 liters. It is run with the drillstem test string, instead of a wireline, and is activated by applying annulus pressure at any time during the sampling flow period. Its samplers can be activated simultaneously or selectively. The pressure-actuated sampling system not only eliminates the safety concerns associated with wireline sampling during an emergency disconnect but also can save 8 to 24 hours of rig time.
Dual downhole test valve. The Iris dual-valve tool (IRDV) uses an intelligent pressure-sensing system to control two downhole valves - a flow control valve and a circulating valve. It uses a pressure sensor and battery-powered microprocessor to receive and interpret coded pressure pulses sent from the surface via the annulus and thus effectively controls well flow during testing.
High flow measurement. The PhaseTester is a three-phase meter that measures high flow rates without separation. This technology works well with the emulsions and foaming oils often found in high-rate flowbacks after gravel packing.
Why conduct deepsea well tests?
The significant capital expenditures required for deepsea developments make it prudent to have the maximum knowledge possible about all reservoirs when creating a development plan.
Seismic surveys and electric log measurements simply cannot provide all of the reservoir detail needed. By adding well testing to the mix, operators gain:
• reservoir compartmentalization data, including communication channels and boundaries;
• adequate sample volumes for determining trace compounds in the fluid (H2S or Hg). This type of sampling is best taken during a testing flow period after the well has stabilized so reactions of the compounds with the drilling fluids and drillstring have ceased. These measurements are critical for surface facility design;
• dynamic conditions data. Testing is the only time reservoir parameters can be measured under dynamic conditions. Maximum flow rate tests often are used to determine likely reservoir potential as it translates into cash flow; and
• regulatory compliance. Some countries require well test results for the operator to recover expenditures.
Deepwater testing concerns
When contemplating any downhole procedure, operators weigh the information or results to be gained against all potential risk factors. The increased subsea depth of well control devices during deepsea testing coupled with the high mobility of the dynamically positioned (DP) vessels that drill these wells amplifies the hazards that may be encountered while testing any well. Taking the costliness of these operations into consideration alongside the safety concerns, it is highly recommended that hazardous operations studies be conducted during the development planning stage as a means to select the optimum well test design.
Experience has revealed several specific challenges that must be addressed and steps that can be taken to ensure greater success and reliability when testing in deep waters.
Planning. Deepwater testing is not a callout-type service. Best results are obtained when well test planning occurs 4 to 6 months in advance of testing. This includes designing the test string, spacing out the subsea test tree in the BOP, drafting the surface well test equipment footprint, and conducting heat radiation simulations and hazardous operations studies, among other details. The hazardous operations study should at a minimum cover drillstem test tools, subsea safety issues and the surface testing equipment.
Speed of disconnect and reconnect. A failed positioning system on DP rigs results in a rapid movement away from location. Thus, well testing systems must be able to reliably disconnect as soon as possible. Electrohydraulic control systems can be used in combination with a fail-safe retainer to enable a safe disconnect within 10 seconds. Petrobras used the first such system in deep waters in late 1999, and it has since proven itself in the field. It provides an alternative to the use of shear rams, which traditional hydraulic and enhanced hydraulic control systems use, as the primary disconnect system, returning the shear rams to a backup position.
Electrical connectors. The electrical connections in electrohydraulic systems can be weak points. Purpose-built, robust connections are being successfully used for deepwater applications. Failures reported in the earliest deepwater testing work have been eliminated.
Riser safety, pollution risk. Retainer valves are used to ensure that no fluids exit the wellbore during a rapid disconnect. These valves may be installed in fail-safe open or closed position, depending upon the results of the hazardous operations study.
Riser umbilicals. Beginning in about 2,000ft (610m) of water, the typical materials used for subsea umbilicals and clamps can react with the environment. Specialized materials and designs have been developed to improve umbilical performance in deep waters. Carefully designed specification, protection and placement of the umbilicals that support well testing controls and inhibitor injection have eliminated previous umbilical challenges.
Hydrates, paraffin and asphaltenes. The common occurrence of hydrates in deepwater wells is addressed by injecting inhibitors at the subsea test tree. This is coupled with the proper selection of fluids for hydrate inhibition. Pressure and temperature at the mud line should be regularly monitored as well. Waxes and asphaltenes typically do not affect well testing but should be sampled, as they can affect well productivity. Further, on any well in which hydrates are even remotely anticipated, a coiled tubing (CT) lift frame should be installed from the beginning. In deep water, CT is the most effective way to clear a hydrate plug.
Test tree and BOP interface. The varying well conditions encountered and the different BOP types and manufacturers create several interface areas to be managed. Among these are the size of and material in the shear joint, the selection of the primary shear ram and a sequence of events in the disconnect procedure.
High rates. Testing wells at high rates creates special considerations in pipe and vessel sizing as well as in the required heating capacity. Relief line sizing and placement becomes critical to the safety of the test set-up and is part of the hazardous operations procedure.
Injection subs. Injection subs that have internal check valves with redundancy and no protruding connections have been found to eliminate the risk of mechanical damage to the sub upstream of the check valve.
Gravel packing. Deepwater tests are often in high-permeability reservoirs. Sand control is necessary in order to prove the well at high flow rates without solids production. Use of screens without gravel packing has sometimes resulted in artificially high skins due to plugging or terminated tests as a result of screen failure. Proper sand control also can allow the completion effectiveness to be evaluated for development planning.
The advance of deepwater testing
The recent additions of fail-safe valves, electrohydraulic subsea BOP control systems and a riser sealing mandrel have made quick, safe disconnects a reality in deepwater operations. As deep offshore well testing experience grows, additional technologies and techniques continue to be added to the operator's list of options.
On the horizon, acoustic controls are being explored to minimize umbilical requirements and create a more robust well testing control system. Pulser technology is advancing to the point that downhole tools will be operated without high-pressure annulus commands, and wireline work will be minimized, if not eliminated. Also feasible is the use of kinetic hydrate inhibitors, which will eliminate the need to inject large volumes of methanol or glycol for hydrate inhibition.
The way forward into deeper waters will continue to come from many directions. In addition to extending the envelope of traditional testing methods, future technologies will bring techniques not practiced today. The ultimate objective is to conduct large-scale well tests without producing hydrocarbons to the surface, thereby eliminating the need for flaring, sample collection for transport or other means of effluent disposal.
As the search for hydrocarbons moves to deeper and deeper waters, traditional technologies will be continually adapted and improved to meet the required challenges. In addition, novel concepts will be developed to meet unique deepwater needs. Recent successes testing deep offshore wells bode well for continued growth in this market niche.