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.
Prediction of pore pressure in carbonate formations is a major challenge. When this challenge is combined with the possibility of abnormal pressure occurrence, accurate pore pressure prediction becomes a necessity. The over pore pressure intervals in those formations narrows the size of the drilling window to ~10 pcf (1.33 ppg) which requires high accuracy of pore pressure prediction. Inaccurate pore pressure data can lead to well-control incidents, poor casing designs, and inefficient reservoir modelling among other things. Therefore, a new model was developed to predict pore pressure in over pressured carbonate formation.
By employing acoustic logging data, a correlation between the effective vertical stress and Poisson’s ratio was developed to be used in combination with formation bulk density measurements in order to predict the pore pressure in 3D space relying on the Poro-elasticity theory. Comparing the results of the prediction process with the available Modular formation Dynamics Tester (MDT) yielded a significant fit. Through this correlation, the abnormal variations in the high pressure carbonate are detected to a significant level of accuracy.
Based on the produced correlation, the results of the pore pressure prediction process showed that the pressure gradient increases from 0.48 psi/ft to 0.52 psi/ft in adjacent carbonates. This gradient reached an abnormally high value at 0.95 psi/ft at the base of dolomitic formation, which then decreases at lower formation. Based on the true vertical depth of these high pressure sequences, this abnormal pressure gradient equates to around 140 pcf (18.7 ppg) mud weight. Having knowledge of this value is substantial for minimizing the number of kicks encountered in these zones.
Thin interbed seismic reservoir predictions, attribute analysis and seismic inversion are the most useful techniques for reservoir characterization using seismic data. The seismic inversion and reservoir properties prediction with multi-attributes and neural network techniques was focused on a complex stratigraphic situation; where a strong lateral facies variation was perceived from well information. The combination of 7 seismic attributes including P wave and density, derived from inversion was used in the step-wise regression. The network was trained with “shale content” data available at well locations to generate a shale volume. 3D seismic data was used to propagate the relationship established with this training.
This paper focuses on the methodology of sand body identification for reservoir development with seismic inversion, multi-attributes and probabilistic neural network (PNN), to demonstrate that multi attributes techniques are useful in the identification of thin sand bodies.
Presentation Date: Wednesday, September 27, 2017
Start Time: 11:25 AM
Presentation Type: ORAL
ABSTRACT: This study provides an improved interpretation and delineation of pore pressure in the Chukchi shelf region. Between 1989-91, five exploration wells were drilled on the Chukchi shelf and an array of drilling performance and petrophysical data were acquired. Resistivity, conductivity, sonic travel time, sonic porosity, and drilling exponent data were used to evaluate formation pore pressure. Normal compaction trendlines were established using depth-dependent relationships then integrated with Eaton and adapted Eaton equations to estimate formation pressures. Four of the five wells were found to contain significant overpressure at onset depths ranging from 1098 to 2317 meters subsea. The overpressure is mainly associated with organic-carbon-rich source rocks that have experienced thermal exposures sufficient for hydrocarbon generation. The driving mechanism for the origin and maintenance of the overpressure appears to be linked to hydrocarbon generation at the wellsites and access to hydrocarbons migrating from the regional generation center beneath the Colville basin to the east.
Pore pressures in many deep sedimentary formations often exceed hydrostatic pressures, a condition termed “overpressure”. If not properly balanced by drilling fluids, an overpressured formation may cause a well to flow to the surface. Overpressure thus forms a hazard to drilling operations if not anticipated in well planning.
The purpose of this study was to develop an improved interpretation and delineation of pore pressure in the frontier Chukchi shelf region. The Chukchi shelf is located offshore northwestern Alaska in water depths typically 50 meters (165 ft) or less. Five exploration wells were drilled on the Chukchi shelf during open water seasons from 1989-91 and an array of drilling performance and petrophysical data were acquired. In this study, resistivity, conductivity, sonic travel time, sonic porosity, and drilling exponent data are used to evaluate formation pore pressure. Normal compaction trendlines are established using depth-dependent relationships then integrated with Eaton and adapted Eaton equations to calculate formation pressure. Four of the five wells penetrated overpressure and hydrocarbon generation is suggested as the driving mechanism behind the origin and maintenance of formation overpressure in the Chukchi shelf region.
The tuning effect of thin interlayers and the influence of different fluids may cause the change of AVO characteristics (Zhao Wei et al., 2006) which can lead to large errors in the analysis of the pre-stack seismic data. In this paper, based on the forward modeling analysis of the "sand replacement" model, the method which can improve the prediction accuracy of thin interlayer reservoir of using the gradient properties of amplitude weighted cosine phase is proposed. In the end, we use the spectral attributes of high quality post-stack data to detect heavy oil in thin reservoir. This method has a good effect in practical application.
Presentation Date: Thursday, October 20, 2016
Start Time: 8:55:00 AM
Presentation Type: ORAL
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.
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.