The main challenges faced by oil sands operators are the cost of operations and the environmental intensity of the recovery processes. The Athabasca oil sands deposit contains bitumen with viscosity typically over 1 million cP. To lower the viscosity of the bitumen so that it can be drained from these reservoirs, it is heated with injected steam by using Steam-Assisted Gravity Drainage (SAGD). This process is effective and enables recovery factors over 60%. The major cost in the recovery process is steam generation and associated water treatment and handling. The combustion of natural gas to generate steam is the main origin of the carbon dioxide emissions associated with SAGD. An alternative to steam injection is the use of solvents co-injected with steam. Solvents dilute bitumen leading to an oil phase with reduced viscosity. Also, there is potential to recycle solvent for re-injection. Thus, solvent added to steam can improve the steam-to-oil ratio and as a consequence can lower the carbon dioxide emissions per unit volume oil produced. In this extended abstract, we describe a phased solvent and heat process that yields improved performance beyond that of SAGD and current solvent-aided SAGD processes.
Steam injection is a widely used oil recovery method that has been commercially successful in many types of heavy oil reservoirs, including oil sands of Alberta. Steam is very effective in delivering heat that is the key to heavy oil mobilization. In the distant past, and also recently, solvents are being used as additives to steam for additional viscosity reduction. This was done previously in California heavy oil reservoirs also. The current applications are in SAGD (Steam-Assisted Gravity Drainage) and CSS (Cyclic Steam Stimulation) field projects.
The past and present projects using solvents are reviewed, and evaluated viz ES-SAGD (Enhanced solvent SAGD) and LASER (Liquid Addition to Steam for Enhancing Recovery). The theories behind the use of solvents with steam are outlined. These postulate (1) additional heavy oil mobilization; (2) oil mobilization ahead of the steam front, and (3) oil mobilization by solvent dispersion due to frontal instability. The plausibility of the different approaches is discussed.
Recent theoretical work is described that compares thermal and solvent diffusion, showing that the time scales of the two processes are quite different casting doubt on the effectiveness of the use of solvents with steam. The numerical and analytical solutions have been compared for effect of cold solvent, hot solvent, steam only, and co-injection of solvent and steam on bitumen mobilization.
The outcome of this study can be used for better understanding of mechanisms and theories behind co-injection of solvent with steam.
Different research reported that the main mechanism for low salinity water flooding in carbonate reservoir is multi ion exchange (MIE) which occurs when the concentration of active ions such as sulfate and calcium is high and the temperature of the reservoir is in the range of 90-110°C. In many cases, due to the reservoir condition and availability of the injection brine, meeting criteria for an effective ion exchange mechanism is not possible. In this study, the feasibility of LSW flooding for oil recovery enhancement from carbonated reservoir at low concentration of active ions was investigated.
Rock and fluid samples from an Omani oilfield were used for the experiments. Different experiments were conducted to study the rock/brine/oil interactions during the LSW process and the recovery improvement. Core flooding experiments were conducted to study the impact of different dilutions on the tertiary recovery. To investigate the effect of salinity changes on fluid-fluid interactions, IFT measurements between crude oil and different brine salinities were carried out at reservoir temperature. Also, effects of LSW (different dilutions) on the wettability alteration were examined by performing contact angle measurement tests as well as spontaneous imbibition tests.
The oil recovery results by core flooding experiments showed a noticeable improvement by switching to the diluted brines. Results of wettability study showed that, due to the lack of sufficient active ions and relatively low reservoir temperature, wettability alteration towards more water wet condition did not occur in this case. But, Interfacial tension measurements showed that brine dilutions reduced oil/brine IFT appreciably. Therefore, in this special case, observations proved that the IFT reduction is the main mechanism contributing oil recovery enhancement. Hence, low salinity water in carbonate reservoirs is recommended for similar cases even when the criteria of MIE mechanism are not met.
Al-Hadhrami, Abdullah (Petroleum Development Oman (PDO)) | Schulz, Ralf (Petroleum Development Oman (PDO)) | Alawi, Hamoud (Petroleum Development Oman (PDO)) | D'Amours, Mubarak Maskari Kevin (Petroleum Development Oman (PDO)) | Barwani, Shihab (Petroleum Development Oman (PDO)) | Jabri, Abdullah (Petroleum Development Oman (PDO)) | Proot, Michael (Petroleum Development Oman (PDO))
The commissioning of new Production Station (Station-H) in April 2012 marks the completion of the Phase 2AB project in the southern area of the Sultanate of Oman. The asset's liquid production has increased by 3 fold and contributes to more than 15% of Oman's production. This project is the world's largest Enhanced Oil Recovery (EOR) with Sour Miscible Gas Injection (MGI) integrating oil and gas field developments. Sour gas is processed through a state-of-the-art processing facility for sweetening and re-injecting gas under MGI to increase oil recovery up to 50%, (i.e. 6x increase over primary RF).
The timeline from discovery of the field-Z in 2002 to commissioning of Station-H in 2012 is top quartile for mega-EOR projects of this type, considering the challenges: deep, high pressure, and sour fluid. Despite the delayed start-up, the first on-stream milestone is considered a commendable achievement. Building a facility to handle the extreme mixture of high pressure, sour corrosive fluids and gas is a technical step-out for PDO.
One of the key challenges was maintaining the station's production despite 2 of the 3 production separators were deemed unsuitable due to compromised internal coating exposing the base material which was not NACE compliant. Therefore, there was no assurance against Sulphur Stress Corrosion Cracking (SSCC) in the event of any contact with sour fluids resulting in 40% capacity loss. A major shut-down of 4 months was recommended to complete several engineering activities (this could be shortened to 62 days by optimisation). Separator replacement was achieved safely resulting in reliable operation at design capacity after restart. The Turnaround was executed without any HSE incidents achieving GOAL ZERO, in total adherence to PDO HSSE standards.
As part of a phased development prior to the 2AB project, several fields were produced beginning in 2004 through Early Development Facilities (EDF) to a nearby Gathering station, capturing of critical information while producing significant early oil. This resulted in sufficient revenues to fund for 2AB and more developments in the area. Within less than 3 years since commission of Station-H, the 2AB project has already achieved return on the investment. The EOR project life will continue to deliver value to Oman for the next 30+ years.
The new station provides the infrastructure for long term development of the area and a number of follow-on projects, which will make use of these facilities: e.g. the already commissioned Phase 3 project in 2013 and Phase 4 development currently in execution and expected to be on-stream by 2019. This work will outline some of the key challenges on the phase 2AB project and how lessons learned were taken onboard to facilitate project delivery of the extended larger EOR/MGI development for follow-up phases and in similarly challenging projects in PDO.
The addition of intermediate hydrocarbon solvents such as liquefied petroleum gas (LPG) to the CO2 stream leads to miscible conditions in reservoirs at lower pressures by reducing the minimum miscibility pressure (MMP). Under miscible conditions, higher recovery is obtained by simultaneous improvement in displacement and vertical sweepout. A compositional model for CO2-LPG-enhanced oil recovery (EOR) was applied to investigate the complicated phenomenon more accurately. The influences of LPG concentration and composition on the displacement and sweep efficiencies during CO2-LPG EOR were examined. Enhanced displacement efficiency was assessed through oil density, viscosity, and the interfacial tension (IFT) between oil and gas. Moreover, the miscible flooding induced by LPG addition resulted in increased solvent viscosity and a lower density difference between the injected fluid and reservoir oil. It also provided a smaller viscous gravity number and improved the sweep efficiency, alleviating the impact of solvent gravity override. As the mole fraction of the total injected LPG and the LPG butane contents increased, significant increments in oil recovery were obtained from the reduction of MMP, oil viscosity, and IFT. The oil viscosity was reduced to 0.65 cp by CO2 and 0.26 cp with the addition of 25% LPG leading to miscible condition. In CO2-swept regions, the IFT became non-zero due to the immiscible conditions. The addition of 25% LPG into the CO2 stream resulted in negligible IFT in the swept area, indicating miscible conditions. For CO2 flooding, 11.9% of the total reservoir area remained in unswept and immiscible conditions despite the long production time. In contrast, the unswept area was reduced to only 2.4% of the total area when 25% LPG was injected into the CO2 stream under miscible conditions, and the viscous gravity number decreased to 0.9 from 3.8 in the CO2 flooding case. For CO2-LPG EOR, oil recovery increased up to 52% as compared with that for CO2 flooding. The amount of incremental oil recovery with 100% butane in the LPG was 16%, as compared with the 100% propane case. Mitigated gravity override enabled CO2-LPG EOR to enhance sweep efficiency. Results indicated that the efficiency of the EOR process with the addition of LPG as evaluated in the compositional model provided more accurate prediction on the performance of CO2-LPG EOR.
History matching a field's performance to understand the reservoir behavior and characterize its static and dynamic properties has been a key activity for reservoir engineers for a long time. Recently, significant effort has been made to devise techniques that allow this process to be automated. These techniques suffer with a number of limitations and often yield History Match (HM) solution points in the uncertainty space that carry certain bias inherent to the algorithm used. Common limitations include: Techniques more often failing to yield any realization with acceptable HM quality at the well levels, Large number of iterations and simulation runs required to minimize the HM errors to acceptable values and, Significant volume of information generated during this iterative process, which becomes unmanageable to interpret and reconcile.
Techniques more often failing to yield any realization with acceptable HM quality at the well levels,
Large number of iterations and simulation runs required to minimize the HM errors to acceptable values and,
Significant volume of information generated during this iterative process, which becomes unmanageable to interpret and reconcile.
Consequently, the assisted HM unfortunately becomes just an iterative process of minimizing the objective function, and the main goal of understanding the reservoir performance gets diluted. When these techniques are applied for Enhanced Oil Recovery (EOR) studies, the list of uncertainty parameters becomes very extensive due to the addition of parameters defining the EOR process itself. As a result, the number of scenarios increases in addition simulations tend to become slower due to incorporation of EOR module and model requirements for space and time resolution to simulate physio-chemical phenomena. Traditional HM techniques then become cumbersome which might lead to inadequate characterization of the potential upside and downside scenarios. This in turn could adversely impact business decisions involving huge capital investments for any field (re-)development opportunities.
This paper will discuss a technique that evolved during the HM exercise for an EOR pilot area in the Middle East. The methodology preserves the idea of Assisted History Match (AHM) to generate multiple HM realizations, however, the solution points are found much quicker eliminating large number of iterations, thereby minimizing the computational expense.
The devised methodology is based on the combination of Design of Experiment (DoE) based Stochastic Uncertainty Management (SUM) workflow with the gradient based calculation (Adjoint) approach to find multiple HM realizations. First, a complete stochastic uncertainty management workflow is applied sampling the entire uncertainty space and multiple realizations are screened ensuring enough variability in parameters and acceptable HM error. The gradient based calculations are then applied on each of these selected realizations to further minimize the HM error.
The Adjoint method yields final set of improved HM realizations with different starting points in the solution space that were obtained via DoE. This helps in two ways – firstly, it covers the entire uncertainty space for better characterization of upside and downside cases and secondly, provides a focused view of the reservoir characteristics.
Additionally, the paper would also offer insights gained from the HM exercise into water coning behavior in a viscous oil reservoir and illustrate the reservoir parameters and their significance that need to be addressed to adequately capture the coning phenomenon.
Two novel methods are presented, that allow estimating downhole P&T conditions by using wellhead measurements in the Schoonebeek steamflood development: one method allows determining flowing bottomhole pressure (fBHP) and the other bottomhole temperature (fBHT). The resultant estimates are confirmed by fluid level measurements and observation well pressure data.
The fBHP calculation is based on the fact that rod loads are dependent on fluid level. A simple but robust model is presented, which accounts for impact of other parameters (pump speed, watercut, etc.) and allows fine-tuning to match available downhole measurements. The fBHT is estimated by using a simplified analytical wellbore heat loss model that is history matched to wellhead temperatures (WHT) at different well rates.
Both models are applied in the Schoonebeek field steam flood development. Their creation was necessary because operational constraints severely restricted usage of standard surveillance techniques like fluid level measurement and use of downhole gauges on hot producers.
The presented methods allow acquiring robust estimates of downhole P&T regime for flowing producers by using easily accessible SCADA data that is continuously collected at the wellhead. These data are normally used to optimize the rod pump operation and have been recorded since the start of the steamflood (2011–2015); hence, by using simplified rod load models and some statistical analysis it was possible to recover and validate the full fBHP/fBHT history for the hot wells – even for the periods when the fluid level measurements were unavailable or inconsistent.
The models were tested and matched against historical field measurements (fluid level measurements and data from observation wells) and were found to provide sufficient accuracy for use in normal operations (P&T within a few bars / 10 degrees C).
The novelty of the methods is in the ability to use existing wellhead data to come up with robust estimates for downhole P&T conditions on flowing wells. Nowadays continuous SCADA are industry standard; thus, near-continuous fBHP and fBHT monitoring can be achieved without using any additional equipment.
Clear benefits are surveillance cost reduction together with improved well/reservoir management; also, extra data helps improving reservoir model history match quality and forecast accuracy.
An original polymer technology, successfully used in Underground Gas Storage (UGS) wells, has been recently applied in offshore gas producing wells. Many gas wells in this area are facing combined water and sand problems due to reservoir depletion, water entries and clayey formation. To avoid critical problems connected to water/sand production, the most common action has been so far to reduce gas production by choking down the wells.
The new technique consists of bullhead injection of water soluble polymers with the main objective to form an adsorbed polymer layer on the surface of the rock, thus providing stabilization. In addition, the products have RPM properties (Relative Permeability Modifiers). They have little impact on gas permeability while strongly reducing water permeability. The combination of both effects will result in a reduction of water and sand production.
Laboratory studies were performed to optimize polymer formulation and evaluate flow properties in reservoir cores. Because of the low reservoir rock permeability (around 10-20 mD), high focus was put on polymer injectivity and RPM effects.
Since 2013, nine offshore gas wells have been treated with polymers. Treatments have shown positive results combining gas rate increase up to 100% and water reduction around 50% while stopping the sand. Details regarding well and polymer selection, job design, execution and production data are provided.
Basta, George Soliman (Scimitar Production Egypt Ltd.) | Korany, Salah Kamal (Scimitar Production Egypt Ltd.) | Kortam, Waleed Tarek (Scimitar Production Egypt Ltd.) | Shaker, Saad (Scimitar Production Egypt Ltd.)
Heavy oil reservoir management using thermal methods is different than conventional reservoir management, especially if the reservoir is highly heterogeneous with limited availability of data. This raises a lot challenges to deal with.
One of these important challenges is timing the conversion of the project from the cyclic steam injection phase to the continuous steam flooding strategy, which allows the steam to contact a larger area of the reservoir, and thus enhancing oil recovery, while optimizing voidage replacement ratio (VRR.) This on the long run increases the project lifetime economically.
Issaran is one of those challenging heavy oil shallow fields in the Middle East, containing reservoirs with heterogeneous properties. Its different reservoirs are managed with different steam strategies. Cyclic steam injection started in 2004 in one of the reservoirs, after that the strategy was converted to continuous steam injection in addition to small cycles in some of the producers to improve communication. Different selected time scenarios of conversion were implemented for each area to enhance sweep efficiency and heat distribution and overcome any undesirable reservoir response such as water encroachment, and deal with highly fractured, highly heterogeneous or low pressure zones.
In this paper, actual field performances will be presented for each formation showing the cyclic steam injection stage and the timing of conversion to continuous steam strategy. A lot of factors will be presented for the steam cycle stage including: voidage replacement ratio (VRR), steam to oil ration (SOR), and the injectivity index performance from cycle to cycle. Then the conversion time from cyclic to continuous steam flooding will be discussed per each area. The relationship between this time with total VRR and the total steam injected in the cyclic stage will be introduced. Spacing between the wells will be mentioned and its effect on the conversion time identified.
Generally the main factors that affect directly on the selected conversion time: communication between the wells, injectivity index and economic factors. The paper will focus on the first 2 factors.
Polymer flood process has the potential to significantly improve sweep efficiency in the fields with viscous oil, due to unfavorable water-flood oil-water mobility ratio resulting in a relatively inefficient water-flood. A successful field implementation would lead to extended production plateau and increased ultimate recovery (EUR). Cairn India Ltd is engaged in Oil and Gas exploration and production in RJ-ON onshore block in India. Mangala oil field is the largest discovered field with significant oil production potential (Total estimated water flood recovery of around 37 %). The field which contains moderately viscous but waxy oil with high pour point is currently under hot water flood to provide pressure support, sweep and prevent any in-situ wax drop-out. Post success of a polymer pilot trial, the full field polymer flood project is being implemented in the field with the concept of a Central polymer preparation plant distributing the concentrated polymer mother solution to the injection wells which are scattered across the field. The mother solution is diluted with the injection water to required polymer concentration before final injection into the well. Full field Polymer Injection it is expected to yield additional recovery of 5–7% of the STOIIP over base water flood.
This paper discusses the challenges faced during the execution of the polymer injection in the full scale with respect to, Supply chain management of polymer w.r.t framing the polymer supply contracts, screening of multiple vendors in different geographical location and the logistics management of large volumes of polymer, Laboratory techniques in screening the polymer, challenges faced in laboratory measurements including viscosity measurement in aerobic/anaerobic conditions, low shear high pressure sampling, and compatibility of oil field chemical additives with Polymer, Operational challenges including viscosity with available water quality & higher oil in water, TSS, Fe content and impact of temperature variation on viscosity of mother solution and diluted polymer solution, Produced fluid handling challenges with Polymer breakthrough with respect to adequacy of oil-water-gas treatment facility to handle emulsion, scaling/gelling issues in heat exchangers and the capacity limitations caused by viscosity and hydraulics.
Supply chain management of polymer w.r.t framing the polymer supply contracts, screening of multiple vendors in different geographical location and the logistics management of large volumes of polymer,
Laboratory techniques in screening the polymer, challenges faced in laboratory measurements including viscosity measurement in aerobic/anaerobic conditions, low shear high pressure sampling, and compatibility of oil field chemical additives with Polymer,
Operational challenges including viscosity with available water quality & higher oil in water, TSS, Fe content and impact of temperature variation on viscosity of mother solution and diluted polymer solution,
Produced fluid handling challenges with Polymer breakthrough with respect to adequacy of oil-water-gas treatment facility to handle emulsion, scaling/gelling issues in heat exchangers and the capacity limitations caused by viscosity and hydraulics.
To summarize, for the full field polymer injection, the challenges discussed with respect to unwieldy logistics of polymer procurement, mother and dilute polymer solution preparation at low shear and high pressure environment followed by polymer breakthrough resulting in tighter emulsion, etc need to be addressed proactively in order to achieve the targeted recovery from the Project. The focused efforts on these areas of concern are the drives for the success of all the stakeholders.