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.
Africa (Sub-Sahara) United Hydrocarbon International finished drilling the Belanga North-1 exploration well located in Doba basin in southern Chad. The well was drilled to a total depth of 1392 m, and encountered three oil-bearing sand intervals--two in the targeted Upper Cretaceous "YO" sands and one in an untested shallower sand. United Hydrocarbon (100%) is the operator. Asia Pacific China National Offshore Oil Corporation discovered natural gas in the Qiongdongan basin, South China Sea. Well Lingshui 17-2--located in the east Lingshui sag portion of the basin at an average water depth of 1450 m--was drilled and completed to a depth of 3510 m. Lingshui 17-2 encountered a gas reservoir with a total thickness of approximately 55 m. Statoil Australia Theta has drilled and completed the Oz-Alpha 1 exploration well in the southern Georgina basin in the Northern Territory, Australia.
The fourth industrial revolution is taking the oil and gas business by storm. Many companies have increased resources for big-data analytics and machine learning. Though no one sees physical oilfield services as in decline, development in these areas may take a back seat to artificial intelligence. This paper contains a detailed discussion of methods and a software tool that has been developed to generate information that predicts formation-face pressures in real time with the help of live bottomhole-pressure data. This paper presents a factory-model approach to improving CT drillout performance that has been used successfully for more than 3 years and has become standard practice.
Formation damage: Do we always need to have a high focus on its prevention, or do occasions exist when it really does not matter? This paper describes a coreflooding program performed with sandpacks at different permeabilities, water qualities, and injection conditions. Because of inherent complexities, understanding the characteristics of perforations in downhole environments is a significant challenge. Perforation-flow laboratories have been used to provide insight into cleanup and productivity mechanisms around perforation tunnels. A high-carbon-dioxide (CO2) carbonate gas field offshore Sarawak, Malaysia, is scheduled for development.
Devon Energy and its debt gets smaller, as Canadian Natural Resources adds to its huge, long-term bet on Canadian heavy and ultra-heavy crude. The recent production freefall could accelerate even further as US sanctions-related deadlines pass, the US Energy Information Administration said. The authors of this paper propose a novel work flow for the problem of building intelligent data analytics in heavy-oil fields. This paper presents the data collected by an ultrasound downhole scanner, demonstrating a novel method for diagnosing multilateral wells. Against the background of a low-oil-price environment, a redevelopment project was launched to give a second life to a shallow, depleted, mature offshore Congo oil field with viscous oil (22 °API) in a cost‑effective manner.
Africa (Sub-Sahara) Marathon Oil has produced first gas from its Alba B3 compression platform offshore Equatorial Guinea. The startup enables the company to convert approximately 130 million BOE of proved undeveloped reserves, which more than doubles its remaining proved developed reserve base in the country. Marathon holds an operating interest of about 65% in the field, with Noble Energy holding the remaining stake. Aminex said that gas production from the Kiliwani North-1 well in Tanzania has reached 30 MMcf/D (about 5,000 BOE/D). The project's commissioning process is expected to conclude with a well test to determine the optimal production rate, which previous test data suggest will be approximately 30 MMcf/D, the company said. The operator of the Kiliwani North Development License, Aminex holds a 54.575% interest in the well.
This paper presents the development and implementation of a production and power optimization system supported by a nodal analysis simulation tool and an updated and calibrated multiphase flow hydraulic model.
The workflow implemented in Castilla field identifies operating conditions that may affect the performance of 577 production wells configured in a complex gathering system, managing multiphase flow for heavy oil with low gas oil ratio and high water cut. Initially, this involves the development of a tool for the systematic data transfer from official databases to the simulation model. Furthermore, the hydraulic model was calibrated to reproduce operating conditions. And once the main nodes and boundary conditions at reservoir, wells, network and processing facility were defined, various optimization scenarios were simulated.
With this workflow the field engineers are capable to propose operating changes to increase production taking into consideration network bottlenecks, power consumption, and facilities limitations. The wells with electrical submersible pumps were ranked into the following categories: pump speed variation, well redesign, surface facilities improvement and drawdown limitation. As a result, actions to be implemented in each well were defined. First, ‘pump speed variation’ classified wells quickly demonstrated how the production and power optimization procedure benefit the field. Specifically, it was possible to optimize the extraction process by increasing the oil production up to 10% using power efficiently. Second, several bottlenecks on the network were identified finding atypical pressure drops, using traditional nodal analysis for pressure, temperatures, velocities, and liquid rates calculation per node. Some of them are related to mechanical configuration and others gas accumulation in pipelines. Third, according to the simulation results, a considerable amount of production can be gained and power consumption can be reduced if these conditions are solved.
This workflow contributes to optimize power consumption and enables faster decision-making to efficiently meet the production targets by increasing oil production and reducing water/oil and power/oil ratios.
Iturraran-Viveros, Ursula (Facultad de Ciencias, Universidad Nacional Autónoma de México (UNAM)) | Muñoz-García, Andrés M. (Instituto de Minerales CIMEX, Universidad Nacional de Colombia, Medellín) | Parra, Jorge O. (JPGeosciences, Helotes, Texas, USA)
SUMMARY A common application in seismic imaging of machine learning algorithms (Artificial Neural Networks) is to produce petrophysical models at seismic scale combining well-log information and seismic data. Here we use these resulting models as prior inputs in full-waveform inversion (FWI). We compute instantaneous seismic attributes to a stacked P-wave reflected seismic section in the Tenerife field located in Colombia and train Artificial Neural Networks (ANN's) to estimate P-wave velocity V The logs are provided by a well near the survey line, allowing images of different rock properties to be used in the inversion of velocities. This process allows us to build an initial estimate of the earth property model, which is iteratively refined to produce a synthetic seismogram (by means of forward modeling) to match the observed seismic data. A nonlinear least-squares inversion algorithm minimizes the residual (or misfit) between observed and synthetic full-waveform data improves the P-wave velocity resolution.
Solórzano, Pedro (Ecopetrol, S.A.) | Ahmedt, Diana (Ecopetrol, S.A.) | Jaimes, Claudia (Ecopetrol, S.A.) | Henao, William (Ecopetrol, S.A.) | Vega, Sandra (Ecopetrol, S.A.) | Guerrero, Cindy (Ecopetrol, S.A.) | Meza, Eliana (Ecopetrol, S.A.) | León, Juan (Ecopetrol, S.A.) | Dueñas, Danuil (Ecopetrol, S.A.)
This paper presents the application of multiple selectives injection zones within a high thickness singled bed heavy oil sand. The results were compared with a single zone completion in the same sand, establishing the differences in several aspects like recovery factor, vertical distribution efficiency, operation styles and completion difficulties.
This approach is based on the application of two methods of water vertical irrigation in a heavy oil sand, first, a singled 300’ zone completion and else, a 3-4 selectives zones completion, separating the equivalent injection in spaces of 60’-100’ thickness each. To route the flow, the packers were located next to thin shale planes most as possible. The objective was use this natural inundation surfaces intentionally as vertical permeability barriers looking forward to this works as a vertical flow controllers beyond wells selectivization, means like flooding separators, inside the heart of reservoir. In injector wells 3 types of behavior profile logs were ran several times within more than two years.
The reservoir under study it is the sand T2 located at Chichimene field, at the Colombia Llanos Basin. It has 320’/250’r of gross/net thickness, physically looks like a singled bed, it is saturated with high viscosity extra heavy oil of 350 cps, it is located at 9000’ measured depth (6000 - 6800’ TVDSS) the permeability shows a broad permeability range of 5 – 10000 mD. Waterflooding was initiated by 2014, the single zone completions wells, were exposed to a 6000 bls/d rate over very high permeability layer and this produced immediate channelization in thin layers only in some weeks after initiated. Producer wells increased water cut to high values, injection rates were controlled as results of its and finally some of the injectors had to be shut in. In the other set of wells, selective applications got separate the sand by 3 or 4 zones, the reservoir sand were irrigated by the same time, at the same rate of 6000 bls/d, almost 2000 bls/d each zone, this time the trends were simply different, means, producers water cut it was low and more stable. The results shows up about 2-3% of RF by simple zone completion in opposite to 6-10% of RF with selectives completions, evidencing a better vertical irrigation.
The case study presented in this paper, it is a successful curiously application of multiple selectives completions within a single sand. This example has been tested in field, it is an effective option in order to increase recovery factor and it will reborn expectations about the use of selectives completions over thick heavy oil sands. This results definitely; it will encourage engineers to think more about mechanical conformance applications in waterflooding.
Trujillo, M. (Ecopetrol S. A) | Delgadillo, C. (Ecopetrol S. A) | Niz-Velásquez, E. (Universidad Industrial de Santander) | Claro, Y. (Ecopetrol S. A) | Rodriguez, E. (Ecopetrol S. A) | Rojas, R. (Ecopetrol S. A)
Prior to starting any Enhanced Oil Recovery (EOR) process, it is desirable to characterize the flow pattern within the affected reservoir volume. This becomes of critical importance for in situ combustion in heavy oil reservoirs, where the mobility ratio is highly unfavorable, oftentimes resulting in channeling or early breakthrough. An inter-well connectivity test through immiscible gas injection aids in characterizing the flow distribution, in addition to: 1) calibrating estimates for sweep efficiency, 2) evidencing geological features that may lead to preferential flow towards a particular well or group of them, or lack of connection amongst them, 3) creating a gas path between the injector and producer wells to enable a safe progression of the combustion front, and 4) evaluating the performance of artificial lift and well control systems under high gas-liquid ratio conditions.
A connectivity test using nitrogen was designed, implemented and evaluated at the Chichimene field, prior to the ignition of the in situ combustion pilot. This process is summarized and described in this paper. This will be the first in situ combustion trial in a deep (≈ 8,000 ft), extra-heavy oil reservoir, and will serve as a data source to evaluate the development of resources under similar conditions in the eastern plains basin of Colombia. This set of reservoirs bears a significant fraction of the hydrocarbon resources in the country and under Ecopetrol operation.
The importance of this pilot makes this connectivity test of even larger relevance to reduce the subsurface and operational uncertainty, identify risks, and increase the probability of success of the combustion process as an option to economically producing these resources.