This paper describes a trial project to evaluate autonomous inflow control device (AICD) technology to better manage water production in a large heavy oil field in Colombia. The Cajua block is part of the Rubiales field is in the Llanos basin of Eastern Colombia, and has reserves estimated at 7.5 billion barrels. One of the main production challenges is the high water cut, or BSW, driven by strong aquifer flow in the underlying sands of the Carbonera formation. Many wells experience early water break-through and must be produced above 95% BSW for long periods of time. Horizontal wells typically produce up to 8000 barrels per day of total fluid with electric submersible pump (ESP) on cold production, and do not utilize any thermal recovery methods. The loosely-consolidated sandstone reservoir has variable water saturation and permeability, which has continuously frustrated operators'’ attempts to manage water production ever since the Rubiales field was first brought online in the 1980's.
In late 2018, a three well pilot project was initiated to evaluate the ability of inflow control technology to manage water influx at the sandface of the horizontal completions. Three wells in the Cajua block were equipped with AICD screens and swellable packers to evaluate oil production and water cut. The AICD technology works by limiting water inflow based on fluid viscosity. Each segment, or compartment, of the horizontal wellbore is isolated by swellable packers, and the AICD creates a higher or lower drawdown on the reservoir depending on the fluid properties, favoring the inflow of high-viscosity heavy oil over the low-viscosity water.
The early production results show that AICD completions can effectively manage water production by delaying water break-through and restricting water inflow from the reservoir. Each of the three trial wells responded positively to the autonomous ICDs, allowing engineers to produce heavy oil wells more effectively with lower cumulative water volumes.
This project marks the first implementation in South America of AICD technology with rate-controlled production (RCP) valves to manage water production in a heavy oil field. It is also the second application worldwide, after Canada, to show that AICDs can effectively to manage water cut in a heavy oil, cold-production scenario.
As part of its facilities modernization project, the Kuwait Oil Company has spearheaded major upgrades to its oil-gathering centers, including improved separation and chemical treatment technology. The remote wellhead platforms must be automated for operations that are normally unmanned, or operations that require personnel only for restocking consumable fluids, maintenance, and restarting after an emergency shutdown. The main equipment must be located on the lower deck of the platform. This includes the booster compressor, test separator, manifolds, wellhead control panel, pig launcher, future pig receiver, and a SCADA system. Maintenance and other activities requiring personnel on site would be conducted by campaign and not routine platform visits.
As part of its facilities modernization project, the Kuwait Oil Company has spearheaded major upgrades to its oil-gathering centers, including improved separation and chemical treatment technology. These strategies may take the form of significant upgrades to existing facilities or the construction of new facilities altogether.
Stanko, Milan (NTNU) | Asuaje, Miguel (Pacific Rubiales Energy & USB) | Diaz, Cesar (Pacific Rubiales Energy) | Guillmain, Miguel (Pacific Rubiales Energy) | Borregales, Manuel (USB) | Gonzalez, Diana (USB) | Golan, Michael (NTNU & MEGO A/S)
This paper describes the challenge of managing and optimizing the production of a large land based oilfield with hundreds of ESP-boosted wells arranged in widely distributed well clusters which production converges to major trunklines traversing the field. The Rubiales field, located in the eastern plains of Colombia has challenging features, characteristics and layout that demand effective model-based production optimization and control. The field's gathering system feeds the commingled production to two central field processing plants.
The flow of the numerous wells and streams of the network are interdependent as there are no gas separation facilities at the clusters or at any other location in the network between the wellhead sources and the entry to the processing plants. This creates an interdependency of well streams. Thus, any production change at a single well affects the pressure and rate of all other wells in the network and consequently the total field production. The water rate from each individual producing well strongly depends on the drawdown and the stage of depletion of that particular well, and how it is controlled by varying the speed of its ESP. High water cuts of most producing wells and the constraints on water treatment and disposal at the field level dictates a need for frequent readjustment of individual well ESP speed.
Adjusting ESP speeds to maximize the field oil production, subject to field water production constraints, must also take into account a variety of additional constraints related to system limitations, ESP performance, power consumption, production operations and reservoir recovery strategy. One cannot rely solely on operational intuition and empirical field practice for individual ESP control. Rather, a model-based optimization system has been implemented, taking into account all field and well constraints. The implemented system is robust, fast and easy to tune. Furthermore, inflow of heavy and viscous Rubiales oil into the horizontal wellbores is driven by a strong and active aquifer in a highly heterogeneous and permeable reservoir. This results in rapid changes of produced water cut in response to small changes in drawdown, demanding effective tuning of a predictable well inflow function for the purpose of optimization.
This paper describes the model-based optimization system employed in the Rubiales field. The system is customized to the large scale and special features of Rubiales, such as the demanding production performance of its wells, the constraints of facilities, and the objective to maximize profit given by production revenues less OPEX.
Prieto, H. (Pacific Rubiales Energy (PRE)) | Lima, E. (Pacific Rubiales Energy (PRE)) | Gaviria, M. R. (Pacific Rubiales Energy (PRE)) | Gil, E. (Pacific Rubiales Energy (PRE)) | Benitez, N. (Pacific Rubiales Energy (PRE)) | Fuenmayor, M. (Pacific Rubiales Energy (PRE))
The experience gained in a unique in situ combustion (ISC) pilot project, in the heavy oil (13° API), water drive Quifa field in Colombia, is presented. The design, construction and operation of the production and air compression facilities are discussed. Under normal conditions, the water cut (BSW) in Quifa is above 90% and the ultimate primary recovery is less than 14%, which imposes strong design and operational challenges for an ISC project.
The pilot project was operated from Nov 2011 to July 2014. A modified inverted-nine spot pattern was used, with all wells instrumented with pressure and temperature devices, as well as the majority of the surface equipment. Real-time monitoring and visualization was developed for proper surveillance of the pilot operation.
This paper emphasizes about the surface facilities designed and selected to obtain the best performance of the process in the pilot. Since this was the first time that an ISC project was carried out in Colombia, there was no previous field performance data available about the quality of the produced fluids under ISC, so the main design data for the project were based on combustion tube tests performed for the Quifa field, and data from different projects worldwide available on technical literature.
The design and operation of the surface facilities considered the effect of ISC on the mechanical integrity of the installations and the environment, with the implementation of the adequate piping class specification and HSE practices to comply with local and international standards due to the presence of H2S and acid water. Early detection systems were installed, which helped to operate the pilot within regulations and strict safety conditions.
With this pilot project Pacific Rubiales Energy has built a valuable learning curve in the design, construction and management of an ISC processes, obtaining a unique experience for future projects of its kind. It should be noted that the implementation of EOR projects of this type constitutes a significant contribution in understanding the relation between subsurface and surface process under In Situ Combustion Process to the future of the exploitation of heavy oil fields.
Gomez, Max (Pacific Rubiales Energy Corp.) | Anaya, A. Florez (Pacific Rubiales Energy Corp.) | Araujo, Y. E. (Pacific Rubiales Energy Corp.) | Parra, W. (Pacific Rubiales Energy Corp.) | Uzcategui, M. (Pacific Rubiales Energy Corp.) | Bolaños, V. (Pacific Rubiales Energy Corp.) | Mayorga, E. (Halliburton) | Porturas, F. A. (Ziebel AS)
Rubiales and Quifa fields are major heavy oilfields (oil gravity ranges from 11.3 to 14.4 °API) in Colombia with a current oil production of more than 264 MSTB and an oil viscosity range from 370 to 730 cP. Horizontal well technology used to drill through unconsolidated sandstones with an active and strong aquifer, under primary depletion, has been used to develop this field. Since 2006, 1,019 horizontal producer wells have been completed using slotted liners (conventional completion) because of the low cost and effectiveness in controlling the coarse-grained sand formation and low fines production.
The high water production rate from the beginning of the operation in the horizontal wells is the primary problem in these fields because of the high cost of produced water treatment and other factors. In formations in which high permeability, high oil viscosity, and strong aquifers are combined, early water influx can result. Water production is predictably associated with the oil production; however, one of the major challenges is to delay the water production for as long as possible. Currently, a large number of wells are closed in that have reached economic limits, primarily caused by high water cuts.
An autonomous inflow control device (AICD) was placed in each screen joint to balance the production influx profile across the entire lateral length and to compensate for the permeability variation and therefore the productivity of each zone.
In late 2012, a new technology project was designed and implemented as a pilot to help address the described issues in horizontal wells. AICDs would be used to maintain equilibrium of produced fluids along the horizontal section of the well, ultimately delaying water coning. After the first pilot is completed, a technical analysis could be conducted, based on the results obtained, and, if possible, the AICD technology could be implemented in additional prospect wells. The AICD pilot was implemented in geological conditions more adverse than wells previously completed with conventional completions and still other wells previously completed with passive but non-autonomous inflow control device (ICD) completions; the pilot will be evaluated with horizontal wells of the area. The main purpose of this paper is to provide details about the selection process, design, and evaluation results for the use of the AICDs in horizontal wells in both heavy oil fields.
A linear unconstrained model predictive control (MPC) scheme has been designed to optimize the operation of dual frequency electrostatic dehydrators in the Colombian Rubiales and Quifa oil fields. This multi-objective controller optimizes operation by maximizing the amount of daily oil production, while maintaining the base sediment and water (BS&W) specification at the exit of the electrostatic dehydrator at or below 1.0%.
The designed controller uses models that describe the dynamics of the dehydrator system to meet the objectives described above. The model of the entire system consists of two empirical sub-models: one for the crude-steam heat exchangers upstream of the electrotreater and one for the treater. Each of these models is used to design an MPC controller for the corresponding subsystem. The electrotreater MPC works as the master controller, dictating crude temperature setpoints to the exchanger MPC. The exchanger MPC then adjusts the vapor flow valve opening to obtain the optimum temperature for the outlet BS&W specification. The electrotreater controller also adjusts the treater inlet/outlet flows and the transformer voltage setpoints to meet the desired objectives.
This control scheme allows for 1) less variability in the output BS&W, 2) maximized daily crude oil production, and 3) tighter control. The decrease in BS&W variability helps ensure that the product quality control and increases the rate of oil production by minimizing the need for further oil dehydration steps. In terms of OPEX, financial benefits are obtained by optimizing the dehydrator operation due to the reduction in the amount of costly emulsion breaking chemicals used in this and other stages of the dehydration process to ensure an effluent BS&W specification of 1.0%. In terms of CAPEX, this control scheme minimizes the need for additional infrastructure necessary to further dehydrate the oil produced to pipeline specifications.
This is the first time such a control scheme is known to have been developed for oil dehydration facilities. The approach proposed in this paper makes further implementation of advanced control systems an intriguing and promising venture that includes benefits such as increased oil production and decreased operating and capital costs.
This paper reports on the benefits of applying Fuzzy Logic Control (FLC) over the traditional Proportional-Integral-Derivative (PID) approach to improve the operation reliability of plant of produced water treatment. Reservoir rocks normally contain both petroleum hydrocarbons and water. This water is frequently referred to as "connate water" or "formation water" and becomes produced water when the reservoir is produced and the fluids are brought to the surface
Produced water is the largest volume waste stream in the oil and gas exploration and production processes. Fluid produced in the Colombian Rubiales and Quifa oil field is composed by approximately 95% of water and 5% of oil. Separation of water from production fluid and its treatment and disposal are critical for the continuous of oil production.
Applying Fuzzy logic as automatic control approach for the facilities that separates the water and treats it has represented a 10% increase in the amount of water treated using the same installed infrastructure. This improvement represents savings in CAPEX of US $ 5.76 per barrel of water that is treated with the previously installed infrastructure. OPEX savings are significant and are related to operating costs that are avoided because (1) by not having to build additional plants to treat water that is processed with the current infrastructure no costs associated with its operation (2) due to the better functioning of treatment plants chemical consumption is reduced and (3) the automation improvement allows much better use of staff assigned to the facilities.
The benefits in operation of the plants associated with fuzzy logic control were achieved (1) on having maintained producing(operating) in more continuous form the water treatment plants, (2) Decreasing the shutdown of the facilities by reducing the variability of the process variables, and (3) by increasing the level of automation of the plants and the reliability in operation.
Application of intelligent control approach is a novelty in the industry of oil fields. The main control approach applied has been Proportional, Integral and Derivative (PID) approach.
Gil, E. (Pacific Rubiales Energy (PRE)) | Quintero, N. M. (Pacific Rubiales Energy (PRE)) | Rojas, L. A. (Pacific Rubiales Energy (PRE)) | Fuenmayor, M. (Pacific Rubiales Energy (PRE)) | Farouq Ali, S. (Heavy Oil Recovery Technologies Ltd)
An in-situ combustion (ISC) pilot project was operated in the Quifa heavy oil reservoir in Colombia from Nov 2011 to July 2014. A modified inverted-nine spot pattern was used. As part of the project all wells were instrumented with pressure and temperature devices.
Parameters such as bottom hole temperature and pressure, gas composition (N2, CO2, CO, O2, SO4, H2S and hydrocarbons), water composition (minerals, pH), oil gravity and gas, oil and water production rates were measured and analyzed daily in order to control the combustion process resulting in improving the volumetric sweep efficiency and oil recovery factor. The continuing monitoring of these variables helped redirecting the combustion front, optimizing air injection and increasing production.
This paper introduces the STAR™ (Synchronized Thermal Additional Recovery) technology, based on ISC concepts, which aim increase the recovery factor and creating value in ISC in a heavy oil reservoir. STAR™ is based on the Synchronization Integrated Model (SIM), a suite of software applications which help to generate the main combustion-related parameters such as H/C ratio, oxygen utilization, air-oil ratio (AOR), air requirement, etc.; evaluate the process performance and identify the position of the combustion and fluids fronts in real time.
Oil production in presence of a bottom aquifer is one of the most challenging issues in reservoir engineering. In most cases water coning happens very quickly and the influx of water restricts oil production and limits recovery. The problem is even more difficult when the oil is heavy because the viscosity contrast is large. In some cases horizontal wells may be used to improve the situation but when reservoirs are thin and the oil is viscous even horizontal wells are of limited use. This paper presents the challenges and potential solutions for Enhanced Oil Recovery in heavy oil reservoirs with bottom aquifer. Existing literature is reviewed for field cases of EOR experience with bottom aquifer for chemical as well as thermal processes (SAGD, steam injection as well as In Situ Combustion). In the case of chemical EOR the chemicals may be lost to the aquifer; for thermal recovery the bottom water can act as a heat sink and affect and steam oil ratio. Some in-situ combustion projects have been successful in such settings but in every case the outcome is the same: the economics of the project can be affected. The paper contains some previously unpublished data of polymer injection in a heavy oil pool with some limited bottom aquifer; for the most part it is a review of the existing literature which may prove useful to practicing engineers who are faced with the issue of developing heavy oil resources in the presence of bottom aquifer.