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.
Valencia, Juan D. (Universidad Nacional de Colombia, Exergy - Modeling and Analytics) | Mejía, Juan M. (Universidad Nacional de Colombia) | Ocampo, Alonso (GaStimTechnologies) | Restrepo, Alejandro (Equion Energía)
This paper address the numerical simulation of the chemically enhanced gas injection technology (ChEGas-EOR) at core and reservoir scales. In this technique, a liquid chemical solution, having engineered properties, is sprayed along with the gas stream. The mist travels through the wellbore and further introduced in the reservoir. Previous lab tests, pilot studies in light & intermediate oil reservoirs indicate that the application of CheGas-EOR allows for a reduction in operational costs, increases the chemical penetration radii and decreases the retention rate in the rock. However, the associated uncertainty is still too high to develop this process on a productive scale. In this work we use a developed phenomenological model to build a tool that assist in design and evaluation of Chemical Gas EOR operations aiming to reduce the uncertainties and optimize oil recovery.
We developed a mathematical model, based on the most important transport and surface phenomena. Non-equilibrium mass transfer between phases during the interception of the chemical solution droplets with the liquid phases. Active chemical concentration in miscible liquid phases is much lower than liquid-based chemical injection opperations. As a consequence, dissolution and adsorption rate of active chemicals with reservoir rocks are slow. The model is base on the extended black-oil model formulation coupled to local mass balance equations of active chemicals. Non-equilibrium mass transfer processes are represented with interception, dissolution and a first order kinetic sorption models.
The model was adjusted and then validated using experimental data from core-.floodint tests. Good agreement of the simulations results with experimental observations were obtained. The model can predict the relevant behavior of the disperse chemical injection in the gas phase in porous media. Also, well injections simulations at reservoir scale using the matched parameters from laboratory, reproduced pilot field results. Simulation experiments predict that the CheGasEOR process can increased substantially the oil recovery factor.
For the first time, a model for disperse chemical injection for EOR applications is developed and validated at core and reservoir scale. The simulation model allows the evaluation of this technology at different scales. Therefore, it is possible to use it to optimize operating conditions and perform sensitivity analysis for field applications.
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.
Africa (Sub-Sahara) Gas was discovered at two separate levels in the Mronge-1 well in Block 2 offshore Tanzania. The discovery is estimated at between 2 and 3 Tcf of natural gas in place, bringing Block 2's estimated total in-place volumes up to 17 to 20 Tcf. Statoil (65%) operates the Block 2 license on behalf of Tanzania Petroleum Development Corporation, and partners with ExxonMobil Exploration and Production Tanzania (35%). Oil was discovered at the Agete-1 exploration well on Block 13T in northern Kenya. The well, drilled to a total depth of 1929 m, encountered 330 ft of net oil pay in good-quality sandstone reservoirs. Tullow Oil (50%) is the operator with partner Africa Oil (50%). Asia Pacific Indonesia announced plans to offer 27 oil and gas blocks in 2014 in regular tenders and direct offers.
Africa (Sub-Sahara) Sonangol's deepwater Orca-1 well encountered oil in the presalt layer of Block 20/11 in the Cuanza basin offshore Angola. The well reached a measured depth of 12,703 ft. Initial well tests saw flow rates of 16.3 MMcm/D of gas and 3,700 BOPD. Cobalt International Energy (40%) is the operator, with partners Sonangol Research and Production (30%) and BP Exploration Angola (30%). Asia Pacific Premier Oil's Kuda Laut-1 well in Indonesia's Tuna production sharing contract has encountered 183 net ft of oil-bearing reservoir and 327 net ft of gas-bearing reservoir. Following evaluation operations, the well will be sidetracked to drill the Singa Laut prospect in an adjacent fault block. Premier is the operator (65%), with partner Mitsui Oil Exploration Company (35%).
Africa (Sub-Sahara) Sahara Group discovered hydrocarbons in three wells drilled in Block OPL 274, located onshore in Nigeria's Edo State. Olugei-1 was drilled to a measured depth of 4537 m and encountered five hydrocarbon zones, with 33 m of net pay. Oki-Oziengbe South 4 was drilled to a measured depth of 3816 m and encountered 64.3 m of net pay in 13 hydrocarbon-bearing zones. Oki-Oziengbe South 5 was drilled to a measured depth of 3923 m and encountered 91 m of net pay in 19 reservoirs. Sahara Group (100%) is the operator. Asia Pacific Sino Gas & Energy Holdings (SGE) flowed gas (coalbed methane) from its first horizontal well in the Linxing production sharing contract (PSC) in China's Shanxi province.
Africa (Sub-Sahara) Eni started production from the Nené Marine field, which sits in the Marine XII block in 28 m of water, 17 km offshore the Republic of the Congo. The first phase of the field produces from the Djeno pre-salt formation, 2.5 km below the ocean floor at a rate of 7,500 BOEPD. Future development will take place in several stages and will involve the installation of more production platforms and the drilling of at least 30 wells. Eni (65%) is the operator with partners New Age (25%), and Société Nationale des Pétroles du Congo (10%). The well's primary target is the Bunian structure: a four-way, fault-bounded anticline, which was defined by a 3D seismic survey. It will be drilled to a total depth of 1682 m.
Africa (Sub-Sahara) Eni successfully completed a new production well in the Vandumbu field, 350 km northwest of Luanda and 130 km west of Soyo, in the West Hub of Block 15/06 offshore Angola. The VAN-102 well is being produced through the N'Goma FPSO and achieved initial production of 13,000 BOED. Production from this well and another well in the Mpungi field will bring Block 15/06 output to 170,000 BOED. Anglo African Oil & Gas encountered oil at the TLP-103C well at its Tilapia license offshore the Republic of Congo. The well intersected the targeted Djeno horizon, and wireline logging confirmed the presence of a 12-m oil column in the Djeno. Total started production from the ultra-deepwater Egina field in approximately 1600 m of water 150 km off the coast of Nigeria. At plateau, the field will produce 200,000 B/D.
Steam injection is a widely used oil-recovery method that has been commercially successful in many types of heavy-oil reservoirs, including the oil sands of Alberta, Canada. Steam is very effective in delivering heat that is the key to heavy-oil mobilization. In the distant past in California, and also recently in Alberta, solvents were/are being used as additives to steam for additional viscosity reduction. The current applications are in field projects involving steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS).
The past and present projects using solvents alone or in combination with steam are reviewed and evaluated, including enhanced solvent SAGD (ES-SAGD) and liquid addition to steam for enhancing recovery (LASER). The use of solvent in other processes, such as effective solvent extraction incorporating electromagnetic heating (ESEIEH) and after cold-heavy-oil production with sand (CHOPS), are also reviewed. The theories behind the use of solvents with steam are outlined. These postulate additional heavy-oil/bitumen mobilization; oil mobilization ahead of the steam front; and oil mobilization by solvent dispersion caused by frontal instability. The plausibility of the different approaches and solvent availability and economics are also discussed.
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.