The complete paper focuses on a system for water separation in downhole horizontal wells. The water produced from the well is not lifted to the surface, but reinjected into suitable parts of the reservoir, either for pressure support or for diposal. The method of water separation and reinjection has been evaluated for oil-producing fields. The complete paper presents details of the technical solutions and an economic analysis.
The concept of downhole oil/water separation (DOWS) has been oriented around hydrocyclone-based technologies. The basic principle is that, with a combination of pumps and a proper water-separation device, water can be extracted downhole and reinjected without being brought to the surface. This offers advantages such as a reduction in the the need for additional water-injection wells and surface water treatments or use of chemicals and thus has cost-reduction potential. The removal of the water column from the surface to the bottomhole also can lead to significant increases in recovery rates because the backpressure, as seen from the reservoir, is reduced. It is fundamentally easier to perform water separation at downhole conditions because of higher pressures/temperatures. This will, in general, reduce the oil/water separation time and will minimize the formation of surfactants.
The system presented in the complete paper represents a different approach to DOWS by using a special pipe separator for horizontal wells.
The core of the basic DOWS system is the pipe separator itself, of a few meters in length, that uses a gravity-based water-separation technique. The separator technology has been developed and tested over several years. The separator is installed with standard techniques for downhole production tubing sections on a horizontal part of the well. The upper completion with the necessary pump is independently retrievable from the separator. This high-efficiency separator can be used for a wide range of water cuts, typically from 10% and greater, allowing it to be installed and activated when the well reaches a certain target water cut. Alternatively, the separator can be retrofitted when the water cut reaches a specified level.
The pipe separator will not be subject to sand erosion because the local flow velocities are much lower than the erosion velocity limit defined for steel components. The API erosion limit is a guideline for safe design related to sand erosion in steel components as a function of several parameters, most importantly fluid velocity.
Injection of the separated water can be performed in several ways, such as by using an electric submersible pump (ESP), injecting at a pressure dependent on parameters such as reservoir permeability and fracturing limit. The injection can be performed either at a lower part of the reservoir relative to the producing zone, or possibly by using the annulus to inject at injection zones located higher in the well. Typically, a Level-5 multilateral completion can be used for the injection of the separated water, either for pressure support to increase the reservoir sweep, or for disposal in an aquifer. A typical system configuration features a separator and an ESP for water injection. An additional ESP can be installed higher in the well if lifting capacity is needed. The size and length of the separator itself will be dimensioned according to the expected flow rates in the well but can operate in a wide range of liquid rates from less than 1,000 to more than 10,000 B/D. The regulation of the separator system is based on a combination of surface analyses of water in oil and oil in water injected, and adjustment of pump speed or rev/min. In addition, the separator is equipped with monitoring instrumentation.
A technoeconomical evaluation has been performed for specific candidate wells in order to understand the consequences of using a DOWS system. The first well presented is an oil well with an expected gradual increase in water production with time. The main areas of attention in the evaluation have been the suitability of the downhole water separator for this application and economical consequences in terms of reduced processing and injection cost, and evaluation of suitable water-injection locations with sidesteps (multilaterals).
An initial analysis of the production profile from the example well was performed. It was clear from the design criteria of the separator that the horizontal separator could be used in this case, and that the maximum expected liquid flow rate of approximately 4,000 B/D would be compatible with a separator fitted within a 75/8-in. liner, with the total length of the separator system being less than 30 m of piping. The expected water removal rate is greater than 99%; in other words, almost all the produced water can be reinjected in appropriate production zones. The combination of downhole separation unit and water injection was evaluated for two units in different wells in the same field initially, with the possibility of adding on other separators. The conclusion was that, based on preliminary well trajectories, significant water injection rates up to 10,000 B/D were achievable, injecting in the same subzone as the producers. The economic impact related to water processing is related to both the processing cost per barrel of water and the need for additional water-injection wells. A typical water-processing and reinjection cost for surface processing and injection [in terms of operating expense (OPEX)] was estimated to a rate on the order of $0.80/bbl. The two different operating configurations are illustrated in Fig. 1. In addition to the OPEX cost of daily water processing and injection, the additional-water injection wells from the surface must be added to the cost model.
Additional reservoir sweeps from the injected water have not been included in this initial analysis because doing so required use of more-advanced reservoir modeling, but a clear potential exists for using the separated water for additional pressure support and increased recovery.
The water-injection branch in this case is based on a standard Level-5 multilateral well branch for the injection zone, meaning that full hydraulic isolation is achieved, with a cased mainbore and lateral. This technology has been well-established and has been in use during the past 3 decades, a prominent example being the Troll development in the North Sea.
In an additional well example from a different field, the focus was to estimate the effect of the downhole separator on the production rate from the well since the water column from the reservoir to the surface had been eliminated. The physical effect was that the static pressure from this liquid column would be lowered, because the density of the fluid was lower. Second, the dynamic (flowing) pressure loss from the reservoir up to the surface would also be reduced if water were to be eliminated. This reduction of the two pressure components can have a substantial effect on the flow rate. In this case, the bottomhole pressure was high enough to establish free flow to the surface. The well in question is horizonally drilled, with no water production initially, but then increasing gradually to greater than 80%. At this stage, the well would not be free flowing. As a result of the separation process, the well can extend its free-flow perod with increased flow rate, with a major subsequent effect on net present value for the well.
In many cases, the wells will need ESPs installed because of low or gradually reduced reservoir pressure. When water is separated downhole, only a fraction of the mass is lifted to the surface and the water separation and handling at the surface is reduced. This can have a net positive effect on process CO2 footprint because of reduced energy consumption. The net effect obviously depends on several factors, but typical guidelines figures indicate CO2 emisions on the order of 0.4 kg/kWh for gas-turbine-based energy generation. This posits emissions increase as a function of water cut, with anticipated values in the range plus 1 kg/BOE when water is produced (water lifted to surface, separated, and reinjected).
The observations and results show that DOWS can have positive effects on several factors, including the following:
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 205960, “Use of Downhole Oil/Water Separation System in Horizontal Wells,” by Ahmed Alshmakhy, SPE, and Ali Abdelkerim, ADNOC, and Nils Braaten, Fluidsep. The paper has not been peer reviewed.
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