The multi-attribute rotation scheme (MARS) is a methodology that uses a numerical solution to estimate a transform to estimate petrophysical properties from elastic attributes. This is achieved by estimating a new attribute in the direction of maximum change of a target property in an n-dimensional Euclidian space formed by n attributes, and subsequent scaling of this attribute to the target unit properties. This approach is performed using well log-derived elastic attributes and petrophysical properties, and posteriorly applied over seismically-derived elastic attributes. In this study MARS was applied to predict a transform to estimate water saturation and total porosity from elastic attributes, using a two- and three-dimensional approach, respectively. The final goal of this workflow is to apply these transforms over seismically-derived attributes to generate volumes of these properties, which can be used in exploration and production settings for reservoir characterization and delineation, as well as soft variables in geostatistical workflows for static model generation and reserve estimation.
A common way to understand the relationship between seismic attributes and a petrophysical property is by the use of rock physics templates or simply by cross-plotting well log derived elastic attributes color-coded by a petrophysical property. Both ways graphically illustrate the relationship between the elastic and petrophysical domains, which can be used to estimate reservoir properties from seismic inversion attributes. MARS is a methodology that uses a numerical solution to estimate a mathematical expression that reproduces the aforementioned phenomena. This methodology uses, as input, measured and/or rock physics-modelled well log information, to estimate a well log-derived transform between several elastic attributes and target petrophysical properties. The objective of this workflow is to apply the resultant transform over seismically-derived elastic attributes to predict the spatial distribution of petrophysical reservoir properties.
Theory & Method
MARS estimates a new attribute (τ) in the direction of maximum change of a target property in a n-dimensional Euclidian space formed by n attributes. We search for the maximum correlation between the target property and all the possible attributes that can be estimated via axis rotation of the basis that forms the aforementioned space.
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.
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.
The Corvina field is located to the north-west of Peru, in Tumbes Basin, Block Z1 (Offshore Perú),
Production behavior of the field, production logging (PLT / MPLT) in existing wells and electrical logging in new wells confirm the formation of a secondary gas cap of higher pressure at the top of the reservoir, due to the effect of being the reservoir below the bubble pressure and gas injection through injection wells in these sands, this began from late 2011. The production behavior of wells shows a low lift efficiency of oil along tubing, due producing in conjunction with high volumes of gas and back-pressure on wellhead.
The workover campaign in 2012 was performed in order to select gas and oil producing sands, and install an "Auto Gas Lift" (AGL) installation, in the gas cap by including in the mechanical completion conventional gas Lift equipment, this permitted optimizing the production of gas and increased oil production.
For design of an installation, a commercial software was used to calculate the size of the injection port, so that allow the passage of required gas volume according to the well flow dynamics derived from nodal analysis.
The application of the technique of AGL in Corvina has been successful, achieving an increase in production wells, noting that one of them was up to 300 BOPD. These results have allowed expanding this technique to other fields of block Z-1, with positive results.
Pico, Antonio (Pacific Rubiales Energy) | Aboud, Jesús (Pacific Rubiales Energy) | Parraga, Felipe (Pacific Rubiales Energy) | Martinez, Jose Antonio (Pacific Rubiales Energy) | Lopez, Gonzalo (Pacific Rubiales Energy)
The central region of the Llanos Basin in Colombia has been characterized by an extensional structural style, where the overall fault pattern consists of normal faults oriented approximately N30°E, dipping East. The structures of the oil fields in Casanare Province have been defined by this type of faults. In this work we establish, for the Casanare Province, the existence of compartmentalized structures formed by the junction between N60° E en-échelon faults and N30E normal faults. In this interpretation, en-échelon faults and folds play a major role in oil accumulations. 3D seismic multi attributes, including volume curvature, coherency and ant tracking, were used to reduce the uncertainties associated with the seismic and well data in order to improve geological constraints, in folds, faults and associated fracture zones. As a result, a new strike-slip fault pattern was interpreted, consistent with a wrench zone, as proposed by Wilcox, et al (1973).
Gomez, Max (Pacific Rubiales Energy) | Florez Anaya, Alberto (Pacific Rubiales Energy) | Araujo, Ysidro Enrique (Pacific Rubiales Energy) | Parra Moreno, Wilson (Pacific Rubiales Energy) | Bolanos, Viviana (Pacific Rubiales Energy) | Landaeta, Libia (Pacific Rubiales Energy)
Rubiales and Quifa are the Colombia’s major heavy oilfields (oil gravity ranges from 11.3 to 14.4 °API) with a current oil production of more than 260 MSTB with an oil viscosity ranges from 370 to 730 centipoises. Horizontal well technology is used to drill through unconsolidated sandstones with an active and strong aquifer, under primary depletion. Since 2006, 604 horizontal producer wells have been drilled and completed using slotted liner in open hole.
The high water production rate from the beginning of the operation in the horizontal wells is the main problem to be controlled in the Rubiales and Quifa fields, due to the high cost of produced water treatment and other factors. Water production is inevitably associated with the oil production; however one of the biggest challenges is to delay the water production as much longer as possible.
Rubiales and Quifa actually have a large number of closed wells that have reached its economic limits, mainly by high water production. This production imbalance is being addressed in the new horizontal wells, using inflow control devices (ICDs). The ICDs is placed in each screen joint to balance the production influx profile across the entire lateral length and compensate the permeability variation and therefore the productivity of each zone.
In 2012, a pilot test has been designed and implemented in Rubiales field with three horizontal wells using passive ICDs completion. The performance of the ICD’s is found to reach the highest cumulative oil production compared to neighboring wells. The main purpose of this paper is to detail the selection process design and results evaluation for the use of the passive ICDs in horizontal wells at Rubiales and Quifa Fields, heavy oil reservoirs.
Rubiales and Quifa fields are the major oilfield in Colombia; two heavy oil reservoirs (API in the range 11.3° to14.4°) with unconsolidated sandstone formation with high permeability, however, there is low productivity in vertical and deviated wells, caused by formation damage from drilling fluids, and cased gravel packing completion.
These two formation damages have been mitigated by applying a successful gravel packing technique in both vertical and deviated wells. On June 30, 2014, the oil production rate was 186 thousand BOPD, of which 14.5 thousand BOPD (7%) came from 162 vertical and deviated wells with the successful gravel packing technique.
The successful gravel packing technique consists on first running a standard cemented 7 inches casing and then cutting the casing in the production zone and enlarge the open hole section from 8.5 inches to 13 or 16 inches diameter to remove cement bond overpassing the washout. Finally, the enlarged open hole section is gravel packed with mesh 20-40.
The completion technology purpose is to increase the well productivity, isolating high water saturation intervals on both top and bottom of the oil zone, reducing the skin damage. Before 2007, 30 wells were completed with conventional cased hole gravel packing. Most of these wells were damaged having to be frequently stimulated with organic treatment; 14 of these wells have been re-completed using gravel packing technique. The results show an increase in the productivity index from 2 to 5 times, compared to conventional completion and showing a maximum increase in total fluid rate from 600 BFPD to 3000 BFPD.
Finally, some examples are presented comparing gravel packing using this technique and the cased hole completion method. Operation procedures, advantages, limitations, and production results are presented in individual well performance comparisons. The successful application of this technology has contributed to increase oil production in Tubiales and Quifa fields development and it has also been extended to other analogue fields.
Normally, oil fields develop, once the exploratory phase and reservoir delineation are concluded, is performed based on a geometric arrangement that involves the spacing of wells according to their drainage radius and therefore avoid drain areas overlap.
Gonzalez, Laureano (Pacific Rubiales Energy) | Ferrer, Jose (Pacific Rubiales Energy) | Fuenmayor, Mac (Pacific Rubiales Energy) | Castillo, Nerio (Pacific Rubiales Energy) | Gil, Edison (Pacific Rubiales Energy) | Farouq Ali, S.M. (Heavy Oil Technologies Ltd)
In-situ combustion (ISC) is being carried out in the Quifa heavy oil reservoir in Colombia, employing four vertical inner wells and four deviated outer wells (inverted nine-spot pattern). Additionally there are four horizontal wells surrounding the pattern, which started producing one year before the combustion project was initiated.
In order to evaluate the project performance key parameters, such as volumetric sweep efficiency and recovery factor must be estimated. Therefore, it is important to have reliable values of drainage area and oil in-place volumes since they are basics for the calculations. Given the complex nature of this reservoir, with a strong water drive, the estimation of the drainage area, oil in place and the recovery factor posed a major challenge. The reservoir is characterized by abrupt permeability and oil saturation changes, resulting in water channeling and well interference.
This paper presents the methodology used to obtain the drainage area and current recovery factor of the ISC pilot project by using numerical reservoir simulation. It comprises the generation of oil drainage maps and cross-plots of what we called “Oil Displaced by Neighboring Wells, ODNW” as a function of time. This approach is more accurate than analytical methods for such complex reservoirs since those methods are based on ideal homogeneous reservoir conditions that assume uniform fluid displacement and a symmetrical advance of the combustion front.
Results are presented for the oil in place, the drainage area, and the recovery factor at one year of air injection. These results are compared with those derived from analytical methods. The methodology was designed to be readily applicable to similar heavy oil reservoirs worldwide.