The extraction of Heavy Oil (HO) from the soon-to-be developed Lower Fares South Ratqa field requires steam injection to enhance HO recovery. The amount of water required for this facility is quite high, up to 210,000 barrels/day (in excess of 33 million liters per day), and the availability of suitable water is problematic, particularly in a dry country such as Kuwait.
Enhancement of Heavy Oil (HO) recovery can be effected via cyclic steam stimulation and steam flood techniques. However, steam generation is highly dependent on the availability of sufficient quantities of suitable water.
Potential water sources for steam generation include seawater, rivers, lakes or underground bodies of water. The last three are unavailable in sufficient quantities in Kuwait and specifically in North Kuwait.
Seawater was initially considered as a source water option for the Lower Fares Heavy Oil (LFHO) project but further investigation identified another potential water source – a Reverse Osmosis (RO) reject water stream from the Sulaibiya Sewage Treatment Plant (SWWTP) – as a feasible option.
After careful assessment, KOC selected the RO reject water stream from the SWWTP as the optimal solution. This innovative application utilizes a currently discarded resource and eliminates the environmental concerns associated with discharging this resource to the sea.
KOC requires up to 210,000 barrels/day water to feed the Once-Through Steam Generators (OTSG's) to produce 80% quality of steam for injection into the wells. The water treatment technologies available in the market were evaluated to ensure that the RO reject stream could be successfully treated to achieve a suitable water quality for steam generation.
The LFHO Project will utilize the SWWTP RO reject stream to enhance HO recovery in North Kuwait. The discharge of this stream to the sea is currently considered as an environmental concern. The use of this reject stream was previously not considered possible as no potential usage opportunities were identified.
This paper covers the usage of this RO reject stream as the source water for steam generation for enhanced HO recovery.
The use of RO treated water streams in the petroleum industry as make-up water for cooling water towers and cleaning applications is fairly common.
The use of an RO reject water stream for steam generation to enhance HO recovery is a novel application for the petroleum industry.
Utilization of Discarded Waste Water Stream for Heavy Oil Recovery:
This paper presents an extensive analysis solvent injection at elevated temperatures to recover heavy- oil/bitumen from fractured carbonates. Three different solvents (propane, heptane and distillate oil - naphtha) were injected at different temperatures representing a wide range of carbon number. Indiana limestone (outcrop) and vuggy naturally fractured carbonate samples (outcrop core samples from a producing formation in Mexico) were selected as core samples. Hot solvent was injected continuously through artificially fractured cores followed by hot water (or steam injection) phase. The optimal temperatures for heavy oil recovery and solvent retrieval, in the subsequent hot water injection, for each kind of rock sample and type of solvent were determined. The results revealed that heavy oil recovery increase with the solvent carbon number used. Also, it was observed that when the temperature is higher than the saturation value for the given pressure curve, the recovery decreases and the lightest component of the heavy oil are dragged by the gas stream.
Past studies have shown that use of diluent injection with ESPs can be an efficient artificial lift method for heavy oil fields. It consists of injecting a light hydrocarbon liquid to reduce the oil density and viscosity. This paper describes an integrated modeling solution designed to maximize the reservoir oil production while minimizing the diluent requirement and keeping the crude oil quality within technical and marketing specifications. The field studied is an offshore heavy oil asset. It consists of two reservoirs with API gravities of 14 and 12, and oil viscosities at reservoir conditions of 70 cp and 500 cp. The field includes some 60 production wells.
Diluent can be injected (1) in each individual well at the ESP and (2) in the surface processing facility prior to the second stage separator. Operating constraints include (1) minimum wellhead pressure, (2) diluent availability, (3) final crude quality specifications, (4) maximum field oil and liquid production rate. The difficulty of the production optimization problem lies in the nonlinearity of the well production curves and viscosity model. In this paper, we develop a Mixed Integer Linear Programming (MILP) formulation by piecewise linearizing the nonlinear behaviors. For each well at each time step, we adjust the black-oil rates from a reservoir simulator to create piecewise linear well performance curves giving the reservoir oil production as a function of diluent injected at the ESP.
The proposed integrated solution is used for the entire production life of the field, which is still in the development phase. The solution is coupled with a reservoir simulator (1) to determine optimal diluent requirements over time, (2) forecast field production of reservoir oil, diluent, water and gas, and (3) foresee eventual bottlenecks in the infrastructure design (e.g. limiting constraints). The proposed solution can easily be used as a Real Time Production Optimization (RTPO) tool to find the optimal operating point based on the latest measurements (or real-time data). The optimal solution ensures the highest field reservoir oil production while meeting all constraints and keeping the diluent consumption at a minimum. The increase of the field oil production rate due to optimal diluent allocation ranges from 2 to 10 %. Cumulative reservoir oil production increases by approximately 3 million std m3.
The uniqueness of the solution comes from the integration of all operating constraints into a single mathematical formulation. The computational time (1s – 10s) of the proposed solution outperforms any classical nonlinear approach. This allows running many sensitivity analyses of the entire integrated asset model.
In heavy oil fields, well longevity is limited by water inflow. Passive inflow control devices (ICDs) are effective in terms of balancing production flow and delaying the onset of water production. Nevertheless, when gas and/or water breakthrough occurs, a passive ICD enables production of the unwanted fluid. Autonomous ICDs can provide additional restriction to the unwanted fluids and can further enhance the production of oil.
The fluidic diode autonomous ICD is functionally based on fluid dynamics technology in which internal geometry directs flow movement based on the viscosity of the fluid. The autonomous ICD enhances oil production while restricting water and gas influx, without the requirement of intervention or moving parts within the device. The result is improved sweep efficiency, which can extend well life and thereby assist in reducing operating costs. Effective design of an autonomous ICD completion is aided with an accurate prediction of the flow behavior through the device. This paper describes flow testing and field performance of a fluidic diode autonomous ICD optimized for the production of very heavy oils with a viscosity above 150 centipoise (cp), while restricting water and gas production.
The test results of the autonomous ICD demonstrate that the fluidic diode can produce more oil while restricting water. In fact, heavy oil can flow at a higher rate with less pressure drop than water. Flow performance of this device has been characterized by measuring the pressure drop versus the flow rate at differing viscosities, confirming that the autonomous ICD effectively restricts undesired fluids, while enhancing the production of oil. Numerical simulations demonstrate an improvement of water reduction by more than 50% compared to standalone screen completions. This technology has been used to promote oil production and restrict water influx in fields where the oil viscosity is greater than 700 cp. This paper also demonstrates the appropriate design philosophy when determining the suitable application of the technology to help maximize oil recovery and minimize water production.
Fluid flow performance is what truly distinguishes the autonomous ICD from other devices. This fluidic diode autonomous ICD is a robust, reliable solution with no moving parts, nor the requirement of intervention of any kind. Its predictable flow performance has been proven through testing, modeling, and field application.
Shell Canada has conducted thermal recovery operations in the Peace River area of Alberta for over 50 years, using a combination of vertical, deviated and horizontal wells. During this time, many different recovery schemes, well designs, and operating practices have been used and assessed to determine the best approach to minimizing well integrity risk from safety, technical performance, and cost standpoints.
The cumulative experience has allowed Shell to have an in-depth understanding of the most appropriate casing and connections for specific thermal service that offer the best long-term performance and integrity. Casing cement design and placement practices are a key component in well construction to obtain superior, long-term, hydraulic isolation performance.
Well operations must be monitored though an effective surveillance process to obtain not only periodic assurance of mechanical integrity of well components, but also detection of inter-well formation anomalies that may lead to well failure or loss of hydraulic isolation if left unidentified.
Monitoring and observation wells can offer key additional insights on sub-surface events and changes, and instrumentation techniques can flag anomalies, as soon as detected, for further assessment and action. This can protect not only the wellbores in use, but also assess the effect of project operations on boundary areas and previously abandoned wells.
Kommaraju, Srinivas Rao (Kuwait Oil Company) | Pandey, Dharmesh Chandra (Kuwait Oil Company) | Ahmad, Al-Naqi (Kuwait Oil Company) | Dashti, Hussain (Kuwait Oil Company) | Al-Khamees, Waleed (Kuwait Oil Company)
Sucker Rod Pump (SRP) and Progressive Cavity pumps (PCP) are two proven artificial lift methods used in horizontal wells cold production applications in a heavy oil green field in Kuwait. However, these artificial lift methods have some limitations with respect to depth, production rates, well trajectory and high viscous fluids and even more when handling gas and sand/ solids.
Other important limitation with Conventional PCP in deviated wells with significant Dog Leg Severity (DLS), is tubing/ rod wear which can result in pump failures & well interventions which will ultimately hinder production.
In view of the above issues, an innovative artificial lift system was selected, combining an Electric Submersible Permanent Magnet Motor (PMM) with a Hydraulically Regulated Progressing Cavity Pump (HRPCP) including a modified stator/ rotor geometry for better gas handling capabilities replacing the conventional PCP.
This paper presents preliminary results from a short field test of the PMM HRPCP system the first of its kind implemented on trial basis in a heavy oil green field operated by Kuwait Oil Company. This artificial lift system helped in lowering the pump intake pressure and reached the pump off condition by achieving optimal pressure distribution along the pump while pumping fluids with higher gas void fractions. This has resulted in production rate increment of 20 percent approximately, reducing the power consumption by 50 %, saving the down time for drive head maintenance and reducing oil deferment. This has ultimately resulted in optimization of OPEX (operating costs) and maximizing profit.
The near wellbore damage due to asphaltenes deposition is one of the major flow assurance issues currently faced by the petroleum industry. This study examines the pore scale flocculation and deposition processes of asphaltenes onto rock matrices. The effect of sand-grain size, clay presence in the reservoir rock, crude oil type, and precipitated asphaltenes type on the depositional behavior of asphaltenes is investigated. The porous media is prepared using sands with two different grain sizes or using sand-clay mixtures. Reservoir rocks were fully saturated with two different oil samples. 8 samples was prepared and they were washed by using either n-pentane or n-heptane, which are known as asphaltene insoluble solvents. In total, 16 experimental samples washed with solvents were subjected to optical microscopy and Scanning Electron Microscopy (SEM) – Energy Dispersive Spectroscopy (EDS) analyses to assess the asphaltene depositional mechanism. For all cases, porosity variations were measured experimentally. Our results suggest that asphaltene-clay interaction can increase the near-wellbore damage due to the strong polar ends in asphaltenes which are attached to clay surfaces and/or asphaltenes that are stuck in clay layers. Porosity of the sand has been found to decrease after the injection of solvents, indicating pore blockage due to asphaltene deposition. While the n-pentane precipitated more asphaltenes than n-heptane, n-heptane asphaltenes occupied more volume and resulted in higher porosity reduction due to higher polarity of n-heptane asphaltenes than n-pentane asphaltenes. Furthermore, the presence of clays and non-uniformity of grain sizes are observed to aggravate formation damage by asphaltenes. The SEM images showed that the interaction of clays with asphaltenes mainly reduces the permeability rather than porosity. The EDS analyses indicate that the impurity content of asphaltenes affect mainly the interaction of asphaltenes and clays.
World class oil and gas operating companies apply supply chain management to minimize the risks of investment costs overrun, delays and future higher operating costs of field development projects. Supply chain is a cross-functional approach to plan the flow of goods and services required by a project, based on its front end loading (FEL) specifications, in order to meet business objectives with a successful execution and total satisfaction of the final customers. This paper presents lessons learnt from modeling the supply chain of a steam-based thermal enhanced oil recovery (EOR) heavy oil field development project in Kuwait.
A critical building block of a supply chain model is the supply-demand matrix, which is prepared using information about the needs of the steam-based thermal EOR assets (natural and physical) and identification of requirements organized in segments, around capital, technology or manpower categories. A preliminary identification was made about local capabilities to meet these requirements.
A work breakdown structure from the front-end engineering design was used to generate a supply-demand matrix with materials including special needs such as energy, water and logistics. The model allows the identification of critical requirements and the information to design alternate options to reduce the risk of lack of supply. One practical result is a map with all required suppliers classified according to the type of goods or services, and the specifications or scope of work for selecting a contracting strategy.
Supply chain modeling provides a best practice to meet the demand of goods and services of complex heavy oil steam-based thermal enhanced oil recovery projects. It would help to guide the process of building capabilities in Kuwait oil industry for this type of recovery technologies, which will play a critical role in long-term business strategy.
Co-injection of solvents with steam increases the oil recovery factor and reduces significantly the environmental impact of steam injection processes. Nevertheless, the quality of the extracted bitumen is important to evaluate the process performance which is affected by the solvent-bitumen interaction. This interaction might lead to emulsion formation and asphaltene precipitation. These unfavorable flow assurance problems are associated with the behavior of asphaltenes in solvent-steam processes. Thus, it is important to observe the factors affecting the interfacial forces among asphaltenes-solvents-water prior to any field application. This work investigates the fundamental aspects of the solvent-bitumen interaction during solvent-steam injection processes. A Canadian bitumen was studied. The role of individual saturates, aromatics, resins, and asphaltenes (SARA) fractions of bitumen on solvent-steam process performance was examined both at liquid and vapor water conditions. The behavior of asphaltenes was investigated through systematic microscopic analyses with the absence and presence of reservoir rock. Also, the asphaltenes behavior after toluene (asphaltene soluble aromatic hydrocarbon) and n-pentane (asphaltene insoluble aliphatic hydrocarbon) addition was observed under the microscope. While toluene completely dissolves asphaltenes immediately, n-pentane leads to asphaltenes precipitation with bigger clusters. After these control experiments, the same tests were carried out with the addition of saturates and/or aromatics fractions of crude oil to the asphaltenes fraction. It showed that saturates lead to aggregation of asphaltene clusters at a higher rate than n-pentane, while aromatics dissolve the asphaltenes at a lower rate than toluene. Hence, it was found that the asphaltenes precipitating power of saturates is higher than n-pentane. However, results reveal that asphaltenes mainly interact with water and aromatics fraction of bitumen. The water-asphaltene interaction causes the emulsion formation and the aromatics-clay interaction is responsible for clay migration and higher amount of asphaltene precipitation. The results of this study help us to understand the factors acting upon displacement of bitumen during solvent-steam processes.
Temizel, Cenk (Aera Energy) | Kirmaci, Harun (Freelance Consultant) | Inceisci, Turgay (Turkish Petroleum) | Wijaya, Zein (HESS) | Balaji, Karthik (University of Southern California) | Suhag, Anuj (University of Southern California) | Ranjith, Rahul (University of Southern California) | Al-Otaibi, Basel (Kuwait Oil Company) | Al-Kouh, Ahmad (Middle East Oilfield Services) | Zhu, Ying (University of Southern California) | Yegin, Cengiz (Texas A&M University)
Diatomites are high-porosity, low-permeability reservoirs with elastoplastic properties and high geo-mechanical responsiveness. They have a great potential for oil recovery despite these drawbacks. Withdrawal of fluids from the reservoir rock leads to subsidence causing compaction and shear stresses. This disturbed stress distribution results in well failures that causes loss of millions of dollars. Successful maintenance of pressure support through optimum injection/production is key to preventing subsidence to mitigate the risk of well failure and achieve better sweep efficiency for recovery.
There have been different approaches to tackle subsidence and well failures in diatomites, including the use of ‘backpressure method’, coupled with a neural network to optimize injection-production to ‘balance’ the rock in terms of stress-distribution and thus decrease well failure due to shearing. However, using such methods may mask other problems the well is experiencing including several mechanical issues that influence production. Another existing approach, satellite-imaging (InSAR) cannot be used to take real-time actions that is crucial in diatomites.
Surface tiltmeter data is collected to undertsand the relationship between injection/production and resulting surface deformation, which also provides information about well-to-well connectivity. A neural network-based approach is followed to determine the nonlinear relationship between surface subsidence/dilation and injection-production. This is then used to build an objective function that works to minimize the differences between well-to-well subsidence/dilation measured by the tiltmeters, by adjusting injection-production for the wells.
In this paper, a method that harnesses real-time surface tiltmeter data to adjust injection-production distribution in diatomites to decrease well failures is used beyond the existing applications of surface tiltmeter, for instance, in the areas of detection of early steam breach to surface in steam operations and fracture orientation. This method also provides real-time data for robust reservoir management of such reservoirs where satellite imaging is not effective.