Technology Highlights
Lifting More Dry Oil by Reducing Water Production with Inflow Control Devices in Wells Drilled and Completed in Consolidated Reservoirs, Bloque 15, Ecuador
F. Porturas 1; I. Vela and J. Pazos 2; and Olivier Humbert 3
Introduction
Horizontal wells have superior production and recovery performance than conventional wells, however they suffer from an early water or gas, coning usually towards the heel. However water or gas can breakthrough anywhere along the well trajectory and not only at the heel, due to permeability variation and proximity of water traps and fluid contacts. Furthermore, conventional completions do not handle effectively heterogeneity or permeability contrasts exposed along the sand face.
Today there is a new type of completion hardware architecture to minimize the heel-toe effect and to delay early entry of high mobile fluids, gas or water and to lift more dry oil to surface, named Inflow Control Devices (ICDs). ICD controls and interrogates more optimally both rock and fluid properties in the reservoir, hence delaying early water breakthrough, balancing flux contribution and enhancing well PI. This early water breakthrough causes reduction in potential hydrocarbon recovery; the operation of the ICD is minimizing reserves left behind. If water or gas breaks through in a well without ICD, these hydrocarbons are lost and cannot be drained subsequently.
This paper presents the results of an ICD completion installed in a well in a consolidated sandstone reservoir in Block 15, Ecuador. The ICD completion architecture was successfully installed in the consolidated sandstone with permeability averaging 250 mD while the hydrocarbon viscosity is about 12 cP. After opening the well into production, was flowing with an initial production of about 4000 BOPD dry oil, currently the ICDs are delaying early entry of water and the water cut raised slowly from 1.5% and after four months of production raised to about 24%, initially it was expected to be about 34%.
The key advantage of using ICDs is that it balances the flow across the entire horizontal section, delays early water or gas breakthrough and consequently a uniform areal drainage and no-bypassed valuable hydrocarbon reserves.
Bloque 15
Location of Bloque 15
Bloque 15 is located in the Oriente Basin, Amazon jungle in Ecuador. The main fields are: Paka Sur Field (consolidated formation) and the Eden Yuturi Fields (non-consolidated formation). Both are clastic reservoir with variable fluid and rock properties. Fluid viscosities varies in the field from 5 cP, 8 cP, 12 cP, 19 cP, 21 cP to 44 cP and corresponding API gravities. Figure 1 shows the location of Bloque 15, Ec and the stratigraphic column.
Geologically the Oriente Basin of Ecuador is part of the upper Amazon River drainage system and covers an area of approximately 80,000 km2 which is very prolific on production of oil and gas. It is geologically continuous with the Putumayo basin in Colombia and the Maranon basin in Peru, separated only by geological arches located north and south east of the basin.
This basin is asymmetrical if it is seen on cross section, it dips gently to the west and south along its broad eastern flank, and steeply eastward along its narrow western flank.
The axial position within the basin is marked by an older north-trending structural lineament and is defined by high-angle faults generated during the Cretaceous. The major oil fields in Ecuador are associated with this lineament. (Smith, 1989).
Stratigraphy
The Cretaceous succession is divided into two main, oil and gas productive formations: the Aptian-Albian Hollin Formation is composed of a massively bedded sandstone that overlies unconformably Jurassic and older section. The Hollin section is micro-conglomeratic at the base, grading up to a mediumand coarse-grained quartzose sandstone. This is the middle or main sandstone. The uppermost section of the Hollín Formation is shaly and glauconitic. It reflects a transition from a dominantly fluvial to a fluvialdeltaic/ shallow marine depositional environment. The Hollin Formation is mostly porous and permeable throughout the basin.
The Hollin Formation has a cumulative production of 2.1 billion bls. and is the main reservoir of the existing oil fields of the basin. The Napo Formation consists of organic-rich shales, bioclastic grainstones and packstones, and terrigenous sandstones believed to have been deposited in fluvial, deltaic to shallow marine environments (White et al, 1991). It is considered that five sandstone members have recorded a successive emergence of the Late Cretaceous shoreline during short periods of regression. From oldest to youngest, these sandstones are named as the "T," lower "U," upper "U," M-2, and M-1 members. The Napo sandstones are typically quartzose, fine to medium grained, well sorted, and may contain glauconite and calcareous cement. Porosity and permeability vary as a function of shaliness and mineralogy variations.
The "T", "U" and “M-1” members, together with the Hollin Formation, account for most of the oil produced in the basin. The Napo reservoirs have produced approximately 1.5 billion bbl. The lower “U” Sandstone, the M-2 sandstone is absent to the west and has produced minor quantities of heavy oil in Eden- Yuturi wells. The M-1 sandstone is isolated at the top of the Napo Formation and produces 19API oil from the Eden Yuturi field located east of the Block 15. This is one of the main producer reservoirs in that field.
Reservoir Challenges
Depending on the type of formation in the reservoirs, traditionally producer wells have been affected by: a) friction introduced heel-toe effect, b) permeability contrasts and c) parts of the wells were positioned close to the WOC and subject to an early water breakthrough. In the heterogeneous reservoir having variable rock properties, high permeability layers, compartmentalization or uncertain reservoir description where conventional completions are prone to preferential drainage along thief zones of high permeability streaks, resulting in a non-uniform reservoir drainage and subsequent areal sweep by-passing reserves (Fig. 2).
ICD Principle
The pressure drop through a nozzle is a result of the static energy in the fluid being converted into kinetic energy and absorbed in the fluid downstream of the nozzle as described by the Bernoulli equation, nozzle based ICDs are independent of fluid viscosity. This pressure drop is described by:
At the reservoir sand face, Darcy law:
Δp = pressures across nozzle,
ρ = fluid density,
v = fluid velocity,
q = flow rate,
A = total cross section area of the nozzles.
There is a constant Cu which is determined by nozzle geometry and geometry of flow and typically between 1.0 to 1.5.
When fluid flows through a nozzle, the pressure inside the high velocity flow down stream of the nozzle is locally significantly reduced. If testing at ambient pressure, cavitation will therefore occur, causing a much higher risk of erosion.
At down hole conditions, this is not a problem because of the high static pressure. To avoid this effect in the test, a back pressure in the range 2/3 of the nozzle pressure is required. ICDs are already qualified by several operators, and successfully installed in a large number of wells worldwide.
ICD Function and Operation
Fluid enters the screen and then flows between screen jacket and base pipe into the housing and through the ceramic nozzles (Fig. 3). When fluid enters the nozzles, the potential energy is transformed into kinetic energy, which is absorbed in the main flow through the base pipe, thus resulting in a pressure drop between the annulus and the tubing. Different nozzle sizes are available, making it possible to design the ICD completion to the required well geometry and flowrate. The ICD nozzle setting can be preset, or alternatively, the nozzle setting may be performed on the pipe deck. The wire wrapped screen part of the ICD system to optimize particle size distribution of bridging material and sand control. ICD operational issue is to improve the oil production in reservoirs with the following challenges: besides the obvious sand control functions, ICDs has two main flow control objectives:
Figure 4. Completions with and without ICDs ...- Obtain a uniform inflow profile along the well by applying adapted flow restriction on high flow rate zones and simultaneously stimulate low to moderate producing zones, hereby delaying water or gas breakthrough, and
- Balance flow rate of highly mobile phases while favouring the less mobile oil. This is achieved by introducing a controlled pressure drop. The major benefits with the tool are: eliminates heel-toe effect (Fig. 4), reduces effects from unforeseen permeability contrasts, ensure an even reservoir flux and a uniform production – which delays water or gas breakthrough. Reduces Water Cut depending to the fluid mobility ratio, and minimize risk of by-passing hydrocarbons reserves.
Figure 5.Well Geo-Control
The key LWD tool used to geo-steer the well is a bed boundary mapper that provides reservoir navigation capability, using a 360° deep, directional measurements with maximum sensitivity to formation boundaries. It is capable to show the orientation of boundaries as far as 21 ft from the borehole, using a combination of state-of-the-art tilted coil technology and multiple frequencies and spacings. Figure 5 shows the well placement, both planned and drilled trajectories. The consolidated formation is very hard and during drilling of the horizontal section 3 drilling bits were changed due to formation hardness.
Figure 6. Final ICD completion architectureField Completion
The horizontal well was completed with ICDs in a consolidated formation at Bloque 15, Ecuador. Accurate placement of well, navigation and real time geo-control data allowed to review and calibrate the ICD base case modelling and to verify the final ICD completion design. ICD nozzle size and configuration was refined and reset at wellsite before running in hole with the use of fully adjustable ICD. Figure 6 shows the final completion layout. The OH packers minimize the risks related to the annular flow, erosion and/or plugging of the screens. The water breakthrough simulation with ICD’s decreased water rate significantly compared to a conventional completion.
Production Results and ICD Performance
The well completed with ICDs shows after 4 months a stable and good production. From field operational experience a WCUT of 34% was expected, currently raised slowly from 0%, to 5%, 10%, 14% to 24 %. The oil cummulative production is about 40% higher than the offset reference well (Fig. 7), and pressure is well monitored and stabilised. The offset well without ICDs and producing from the same formation shows a stronger decay in pressure and oil production after similar production time.
Conclusions
The first ICD installation in a consolidated formation in Bloque 15, Ecuador, shows higher performance than a conventional completion reducing water cut, balancing flux, pressure monitoring and delaying an early water breakthrough. ICDs show an efficient restriction of high mobile phases but favouring the less mobile oil (12 cP viscosity) in a formation averaging ca. 0.2D in permeability. WCUT is low (initiallly expected about 34 %) and showing higher oil production compared with offset wells.
Early ICD feaseability and base case simulation of scenarios allowed an efficient field operation.
Removable housing options was used and real time data facilitated nozzle size refinement to be used prior to placing the ICD completion hardware in the ground.
Geosteering allowed to place the well 20% closer to the formation top compared with the plan for the consolidated formation.
Correct application of new technology, team work and planning, is applied in Bloque 15, Ecuador, to minimize water production, to lift more “dry oil” and to achieve an efficient reservoir drainage.
It is concluded that Inflow Control Device proven technology is beneficial and successful in Bloque 15, Ecuador, and its application will be considered in other fields.
Acknowledgements
We thank Petroamazonas for allowing this publication. A special thank to Jose Reina (Petroamazonas) and to Arthur Dybevik for preparing the geoilllustrations.
References
Smith, Lawrence, 1989, Regional Variations in Formation Water Salinity, Hollín and Napo Formations (Cretaceous), Oriente Basin, Ecuador, AAPG Bulletin V73, No 6 (June 1989).
White, Howard et al, 1991, Reservoir Characterization of the The Hollin and Napo Formations, Western Oriente Basin, Ecuador, AAPG 62 ,1991.
Davila, Edmundo et al, 2009, First Applications of Inflow Control Devices (ICD) in Open Hole Horizontal Wells in Block 15, Ecuador, SPE123008, LACPEC, Cartagena, Colombia, 31 May-3 June 2009.
Corresponding author: F. Porturas: Email