Brad Dewalt, Daniel Shields - Granherne Inc.
Exploration and drilling in the Gulf of Mexico’s Lower Tertiary has steadily increased since 2001, and has shown that this area holds significant quantities of producible hydrocarbons.
Due to the unique physical characteristics of these fields, a number of flow assurance challenges must be addressed to ensure the wells can be produced successfully and allow for the greatest possible recovery.
Deepwater Miocene production always is a challenge. Hydrate formation must be prevented during normal flow and shut-in conditions; wax deposition must be managed, and slugging can threaten disruptions in production, among other things. When these are combined with extreme well depths, tight reservoirs, and less than ideal fluid properties, the flow assurance challenges are magnified and require new, innovative directions.
Flow assurance challenges
Lower Tertiary reservoirs present flow assurance challenges from the physical characteristics of the reservoirs and also the properties of the hydrocarbons within. A review of Lower Tertiary properties illustrates some of the flow assurance issues. These items do not represent all Lower Tertiary reservoirs. Each field has its particular features and obstacles. The reservoir characteristics are:
- Reservoir depth, both below sea level and below the mudline, is the primary challenge. With reservoir depths below 30,000 ft (9,144 m), static head will restrict flow and the reservoir likely will require artificial lift to enhance production. Additionally, depressurization of the flowline and riser to a pressure outside of the hydrate formation region is unlikely due to the water depth.
- The Lower Tertiary consists of older, more compact sediments than the Miocene Trend. The rock tends to have less favorable porosity and permeability, resulting in low productivity indices. When targeting high production rates, downhole pressure losses increase, making less pressure available to overcome the static head in the production tubing and riser.
- Oil in the reservoir is relatively high density crude with a low gas-to-oil (GOR) ratio and a low bubble point. The crude also can exhibit high viscosity and high wax appearance temperature (WAT).
- Lower Tertiary reservoirs can be highly fractured with little aquifer support. This can result in a rapid depletion of reservoir pressure, possibly requiring the addition of water injection wells to maintain production.
- A benefit to flow assurance is that Lower Tertiary reservoirs tend to have high pressures and temperatures. This can help maintain production rates and minimize wax and hydrate risks, but it can create problems for subsea designers. Subsea facilities may have to withstand up to 20,000 psia shut-in pressures and materials have to be selected that can accommodate temperatures to 250 °F (121 ºC) and higher.
Lower Tertiary case study
To illustrate the differences between flow assurance challenges in a typical Lower Tertiary reservoir compared to a typical Miocene reservoir, the following is a comparison of the flow characteristics of a Miocene well compared to those of a Lower Tertiary well. An analysis illustrates how various types of artificial lift methods enhance recovery from Lower Tertiary wells and looks at advantages and disadvantages of each type.
The methods reviewed are as follows:
1. Natural flow –Wells to flow naturally, without the assistance of artificial lift
2. Gas lift – Gas lift will be injected either downhole or at the riser base at a rate between 5 MMcf/d and 15 MMcf/d
3. Wellhead multiphase pump (MPP) – Pressure increase between 1,000 psia and 3,000 psia at the wellhead
4. Downhole ESP – Downhole pressure increase of 2,500 psia
5. Pressure maintenance – Assumes a constant reservoir pressure with increasing water content.
A well model was created in PipeSim 2007 using the reservoir and fluid properties shown in the table on page 41.
Because of the low PI, the Lower Tertiary well has a rapid decrease in flowing wellhead pressure as the flow rate increases.
If a wellhead flowing pressure of 4,000 psia is required to deliver production to a host, the maximum possible rate for the Lower Tertiary reservoir is 15,000 b/d at a reservoir pressure of 20,000 psia. When reservoir pressure decreases to 15,000 psia, the maximum flow rate is 7,000 b/d. The system does not free flow at a reservoir pressure of 10,000 psia. In comparison, the Miocene reservoir can produce 12,000 b/d when the reservoir drops to 10,000 psia.
Gas lift
Injecting gas downhole is a straight-forward way to reduce the static head in a production system. Injected gas lightens the liquid column by reducing the liquid density, increasing the bubble point pressure, and generating a higher gas volume once the system pressure decreases to below the bubble point pressure.
Advantages
- Known technology
- Reliable (fewer moving parts)
- Relatively low subsea capex
- Not limited by tieback distance
- Can help mitigate slugging
- Flexibility of injection locations (downhole, wellhead, riser base)
- Riser base gas lift can assist in flowline depressurization.
Disadvantages
- Injection depth is potentially limited by high injection pressure
- High gas rates are required to sufficiently boost GOR
- Increases the total volume through the flowline (i.e. larger pipe might be required)
- Increases the JT cooling through the system (i.e. additional insulation might be required).
For Lower Tertiary wells, low GOR fluids typically have a low bubble point pressure. This, plus high flowing pressures, means that gas likely will not break out of solution until some point downstream of the wellhead. To benefit from injecting gas lift downhole, enough gas has to be injected to increase the bubble pressure to a point within the operating envelope of the production tubing.
The addition of gas shifts the phase envelope upward, increasing the pressure at which gas breaks out of solution for a given temperature. To liberate gas at the target injection pressure of 5,000 psia and a temperature of 175 °F, the production fluid GOR must be increased from 250 cf/stb to approximately 2,000 cf/stb, which is equivalent to injecting 17.5 MMcf/d of gas to 10,000 b/d of oil.
In this example, 5 MMcf/d to 15 MMcf/d of gas lift is injected at a depth of 5,000 ft below mud line. Improved deliverability from lift gas is more pronounced as production flow rates decreases. At high flow rates, the gas lift in the system increases the frictional losses to such a degree that benefit of downhole lift gas injection is limited.
As flow rates decrease and static forces become the dominant mechanism for pressure loss, the reduction in hydrostatic head benefits production, allowing the well to produce at around 3,000 b/d for a reservoir pressure of 10,000 psia, where the system previously was unable to flow. For this production system, increasing the gas lift above 5 MMcf/d does not significantly increase production, due to the increase in frictional losses at higher gas rates.
An alternate way to introduce gas lift is injection at the riser base rather than downhole. The benefits of riser base gas lift is that the injection pressures are lower, there is no need to install a gas lift line to the wellheads, and the well completion program is simpler. However, injecting gas at the riser base reduces the amount that the static head can be decreased, as this is typically the shallowest point in the system.
Although gas lift injected at the riser base is not as effective as downhole lift gas, the effect of increasing the GOR in the riser is to allow the system to produce an additional 1,000 b/d at a reservoir pressure of 20,000 psia. As seen with downhole gas lift, as the reservoir pressure declines, the effectiveness of riser base gas lift increases.
Gas lift, while moderately beneficial to increasing the production at high reservoir pressures, has its greatest benefits at lower reservoir pressures and lower production rates, thus extending field life. The rate at which gas lift can be injected is limited by the resulting increase the frictional losses compared to the decrease in static head. Therefore, downhole injection does not provide any significant production increase compared to riser base gas lift, since insufficient gas mixes with the reservoir fluids to allow for gas breakout in the production tubing.
Design constraints on the gas lift hardware limit the injection pressures to less than 5,000 psia, which limits the depth that gas lift mandrels can be installed downhole, limiting the available reduction in static head. These issues, combined with the increased complexity of downhole gas lift injection, suggest that riser base gas lift may be a preferred way to increase production from a Lower Tertiary well.
Multiphase pumps
A number of subsea multiphase pumps (MPPs) are available and in use in subsea developments around the world. The main types are twin screw pumps and helico-axial pumps. These pumps can be installed directly on the individual subsea trees or as an MSV retrieval pumping skid that ties into the inlet of the flowline.
Advantages
- More reliable than electric submersible pumps (ESPs)
- Installed on the sea floor
- Can be retro-fitted into a subsea development
- Can be replaced with an MSV
- Various pump inserts can be selected based on expected fluid properties.
Disadvantages
- High capex (pump and power cable)
- Large/heavy topsides equipment
- Performance affected by change in fluid properties (GVF, water cut)
- Production from multiple wells can be affected by a malfunctioning pump
- Large power requirements
- Fluid must be able to reach the wellhead.
The MPP pressure boost is a function of the type of pump and the gas volume fraction (GVF) of the fluid as it enters the pump. At low GVFs, MPPs can supply a pressure differential up to 1,500 psi. Both types of MPPs normally can handle GVFs up to 98%, but the differential pressure decreases to potentially less than 500 psi at these high gas fractions.
Two pumps in series can permit a greater increase in the total overall pressure boost. Power requirements can be up to 2.5 to 3 MW per pump, and a variable speed drive, lubrication system, associated power cable, and a topsides power source are required. The power depends on the total flow through the system, the desired differential pressure, the GVF of the fluid, and the length of the power cable.
One advantage is that for this low GOR fluid, the inlet GVF should be very low at most operating conditions. If the fluid entering the pump was single phase over the life of the field, it would be possible to have differential pressures much higher than the 1,500 psi of a typical MPP. The bubble point pressure of this fluid is approximately 1,500 psia, so it is likely that the fluid entering the pump will exist as a single phase.
Where a differential pressure of between 1,000 psia and 3,000 psia is imparted by a generic MPP, by lowering the required flowing pressure at the wellhead, multiphase boosting can increase production by approximately 1,000 b/d to 4,000 b/d for the range of reservoir pressures.
Boosting at the subsea wellhead increases production flow rates over the life of the field and has the ability to extend production to a point below a reservoir pressure of 11,000 psia, where by free flow, the fluid would be unable to reach the mudline.
Because of the low PIs, the MPP pressure boost is offset by the increase in drawdown as the flow rate increases. For example, a 4,000 b/d increase in production corresponds to a 2,000 psi increase in drawdown, burning off much of the pressure obtained from the 3,000 psi boost from the pump. Therefore, the overall rate increase achieved by an MPP for this sample Lower Tertiary well is limited compared to a Miocene well.
Additionally, since most of the hydrostatic head losses are in the production tubing, the challenge remains getting the fluid to the pump.
Electric submersible pumps
Assessment of the hydraulic performance of an ESP was conducted on the same basis as the mudline boosting study. A fixed increase of 2,500 psi pressure was assumed in the production tubing. This is conservative as ESPs can deliver double this based on a 5.62-in pump at 1,500 HP delivering 10,000 b/d.
Advantages
- Large pressure boost
- Installed downhole, closer to the reservoir
- Typically more efficient than mudline pumps (i.e. lower power requirements)
- Multi-well field can continue to produce if one ESP goes down
- Lower capex than MPPs
- Typically smaller topsides equipment footprint and weight than MPPs.
Disadvantages
- Mechanical reliability concerns
- Cost of repairs (tubing usually must be pulled with a drilling rig)
- More complex completions.
Downhole ESPs can boost production by 3,000 b/d across the range of reservoir pressures. A downhole ESP increases production flow rates over the life of field, and has the ability extend production to a reservoir pressure of 10,000 psia, where by free flow, the production would cease to flow.
The ESP study results compare to the rates achieved when boosting with an MPP between 2,000 psia and 3,000 psia. The main difference between the two pumping cases would be near the end of the life of the field, if the reservoir does not have enough pressure to supply flow to the MPP. Being closer to the reservoir, an ESP should continue to produce for a slightly longer time. This would have to be taken into account when performing an economic assessment of the development.
ESPs require less capex, but could have much higher opex should a failure occur. The additional oil recovery possible later in field life could offset some of these costs, but would have a very low net present value at the onset.
Pressure maintenance
Rather than a mechanical increase in flowing pressure, water injection can maintain reservoir pressure. This requires additional wells and subsea hardware, but may result in much higher recoverable reserves. The cost of drilling Lower Tertiary wells is substantial, so adding additional water injection wells would increase the overall cost of the project.
Advantages
- Known technology
- Good reliability.
Disadvantages
- High overall capex (drilling, subsea, and topsides)
- Processing of additional water topsides
- Scaling concerns
- Reservoir souring
- Corrosion concerns
- Additional topsides equipment (seawater treatment, injection pumps)
- Faulted reservoirs require multiple injection wells.
For this case study, it is assumed that water injection can maintain the reservoir pressure at its initial 20,000 psia. Rather than showing the flowing wellhead pressures as a function of pressure, curves were generated for a range of water contents. The water content can affect system capacity. Based on maintaining a reservoir pressure of 20,000 psia though water injection, the capacity for a 6-in NB system drops from 14,000 b/d at a water-cut of 0% to 12,000 b/d at a water-cut of 75%.
The increase in water content does not significantly decrease the flow rate over time, as the oil operates in the single phase for the majority of the production system. Therefore, lowering the overall gas content of the system does not have as much of an effect as it would for a high GOR fluid.
All boosting mechanisms reviewed in this case study have shown to provide some benefit to increasing production rates and extending field life. The decision among the options will be based not only on the hydraulic benefits, but also on the costs and perceived change in risk.
Where is the Lower Tertiary?
The Miocene Trend corresponds to the Miocene Epoch and dates 5 – 24 million years ago. The depth below sea level of this trend ranges from 8,000 ft (2,438 m) for the Upper Miocene to 30,000 ft (9,144 m) for the Lower Miocene, in water depths between 1,000 ft (305 m) and 9,000 ft (2,743 m).
The trend extends across Mississippi Canyon, Ewing Bank, Atwater Valley, Green Canyon, the northern part of Walker Ridge, and the eastern part of Garden Banks. Major development of this trend in the deepwater Gulf of Mexico began in the 1990s, with projects such as Thunder Horse, Na Kika, Mad Dog, and Neptune. Recent Miocene Trend projects and prospects include Knotty Head, Pony, Kodiak, Bigfoot, Tubular Bells, Mission Deep, and Thunder Hawk.
The Lower Tertiary Trend encompasses the Upper Paleocene and Lower Eocene of the Lower Tertiary (52 to 60 million years ago), and ranges from approximately 12,000 ft (3,658 m) to 35,000 ft (10,668 m) below the sea level in water depths between 4,000 ft (1,219 m) and 10,000 ft (3,048 m).
The Lower Tertiary Trend begins in the western Gulf of Mexico in the Perdido Fold Belt in Alaminos Canyon, and moves east into Keathley Canyon and Walker Ridge. It also may include the southern portions of Garden Banks, Green Canyon, and Atwater Valley. The current known extent of the Lower Tertiary Trend is approximately 80 mi (129 km) wide and 300 mi (483 km) long.
