Individual-zone selectivity schemes enables production from either zones individually.

A 781-sq-mile (2,000-sq-km) block in Ecuador’s tropical rain forest comprises four oil fields and drains several layered formations, some of which are oil-producing zones. With more than 500 million bbl of proven reserves, this block accounts for 20% of Ecuador’s current total oil production. These reservoirs are characterized by low pressures and low gas-to-oil ratios (GORs). Accordingly, most wells employ some form of artificial lift, with 176 wells being produced with electrical submersible pumps (ESPs).

These fields reached a cap of 100,000 b/d in 2006. Thereafter, production dropped by about 20%, spurring the operator to undertake an aggressive drilling program to restore field production levels quickly and to begin building them beyond previous levels. The objective was to produce an average 107,000 b/d in 2008.

Unfortunately, rig availability is very tight in the area, and drilling costs are high. It was obvious that delays in well completions were costing considerable money in deferred production. This situation led to a decision to let one well do the work of two by producing simultaneously from two reservoirs, doubling the effectiveness of each drilling rig to add production. Not only would production volumes rise more rapidly, but significant drilling costs would be saved, and even though completion cost per wellbore would go up, the added expense would not equal the cost of casing and completing two well bores.

Nacional de Hidrocarburos (DNH), the country’s national hydrocarbon board, is the regulating body responsible for overseeing hydrocarbon production in Ecuador. There are rules in place to address commingling of production from multiple zones. According to the regulations, each producing zone must be produced and monitored separately and each reservoir tested individually.

Previously, the operator had tried to save money by selectively completing wells in two zones using isolation packers with sliding sleeves. First one zone would be produced, and then the other by way of a simple wireline intervention implemented through an ESP bypass system. Shifting the sleeves allowed production to be switched from one zone to the other (Figure 1).

While some costs were saved, there were several disadvantages. First, to abide by the regulations, only one zone could be produced at a time. Second, one pump had to do double duty, which meant that if the reservoirs had different production characteristics or flow potential, the pump was never quite perfect for either zone. And if the pump failed, both zones were shut in until repairs could be made. This scheme also meant that production management from either of the two reservoirs was, by definition, suboptimal.

Some attempts had been made to install dual intelligent well systems in a few of the wells to satisfy the regulations by installing downhole flow control valves and permanent downhole monitoring and metering techniques. It was thought that if production was accurately measured at each zone, it could be commingled in the production tubing without violating the rules. In theory, this worked, but practically, it was costly to operate and maintain and created several risks, not to mention the fact that sometimes it is not beneficial to commingle different oil compositions in the well under specific reservoir temperatures and pressures.

To satisfy the regulations, each system must be periodically shut down and the flow control valves and measuring systems individually configured to measure production from each zone, resulting in deferred production and potential mechanical problems.

A double play

A new plan was conceived through the implementation of both completions and artificial lift technology. The decision was made to install dual ESPs with dual concentric production strings in each well, thereby satisfying the regulations to produce each zone independently, but simultaneously (Figure 2).

With separate ESPs installed, each could be selected precisely to optimize production from the reservoir it drained. As the program expanded to additional wells, production from each reservoir could be optimized by remotely monitoring downhole and surface production parameters and entering the data into a field production management program. Simply by implementing the program, the operator would effectively double the production potential of each well drilled at a modest incremental cost.

Previous experience in installing dual concentric ESP completions provided historical evidence that the system could work at a cost comparable to that of the intelligent dual completion techniques.

The design

The lower ESP is encapsulated in a sealed shroud. Production enters from below the 95?8 in. seal bore packer and is routed to an eccentered bypass string that goes past the upper ESP and ties into the inner 27?8-in. tubing of a concentric production tubing string beginning just above the upper pump (the outer tubing string diameter is 51?2 in.).

The upper pump draws from the upper zone, and production is routed to the annulus between the concentric tubing strings where it flows to the surface. The annulus has the equivalent cross sectional area of 3.958-in. tubing. Both ESPs have independent Phoenix downhole monitoring systems; so individual production and pump operational data are transmitted to surface via the ESP’s power cable.

At the surface, a dual concentric tree maintains complete separation of flowstreams from each well, and surface instrumentation can monitor each
individual zone’s production and each pump’s performance. Individual variable speed drives optimize each pump’s rate and speed.

The completion equipment was modeled using the Schlumberger TDAS tubular design and analysis system. Using this program, extremes of each operating condition can be modeled and simulated to ensure that tubular loading limits will not be exceeded if one or the other system goes down or if both are operating at full flow. Both axial and hoop stresses were analyzed as were tubing movement limits. DesignPro ESP design software was used to model each producing zone so the optimum pump size for each zone could be chosen to match individual zone target rates.

First time charm

Thanks to a complete stack-up test conducted at the Schlumberger Artificial Lift Center of Excellence in Inverurie, Scotland, the first installation was implemented without incident. Both ESPs were started, and initial production of 3,784 b/d was recorded. Production from one zone with one ESP was 1,570 b/d, which represented an increase of 140% compared to the volume that would have been expected from a single well using previous completion techniques.

Seeing the benefit of the first dual ESP completion, the operator quickly launched a plan to equip additional wells. As of May, 2008, there were 11 wells in this block with concentric dual ESPs running. Cumulative production is delivering considerably more oil than could have been expected from 11 single wells.

Based on the 11 installations completed to date, costs compare as follows:
• Single ESP completion costs ~
US $600,000 (including rig time and equipment);
• Drilling an additional well
> $3 million;
• Intelligent well system cost ~ $1.8 million (including rig time and equipment); and
• Dual concentric completion cost ~ $1 million (including rig time and equipment).

To match the dual concentric completion in terms of production potential and flexibility would cost three times as much, and it would have taken twice as long to implement.
By the end of 2007, production levels had returned to about 100,000 b/d.

The same production strategy will be employed to increase production to the 2008 goal. The systems also can be used offshore in developments where commingling of production is a problem.