The Pelican Lake heavy oil field located in northern Alberta (Canada) has had a remarkable history since its discovery in the early 1970s. Initial production using vertical wells was poor because of the thin (less than 5m) reservoir formation and high oil viscosity (600 to over 40,000cp). The field began to reach its full potential with the introduction of horizontal drilling and was one of the first fields worldwide to be developed with horizontal wells. Still, with primary recovery less than 10% and several billion barrels of oil in place, the prize for EOR is large.
Initially, polymer flooding had not been considered as a viable EOR technology for Pelican Lake due to the high viscosity of the oil, until the idea came of combining it with horizontal wells. A first - unsuccessful - pilot was implemented in 1997 but the lessons drawn from that failure were learnt and a second pilot met with success in 2006. The response to polymer injection in this pilot was excellent, oil rate climbing from 43bopd to over 700bopd and remaining high for over 6 years now; the water-cut has generally remained below 60%.
This paper presents the history of the field then focuses on the polymer flooding aspects. It describes the preparation and results of the two polymer flood pilots as well as the extension of the flood to the rest of the field (currently in progress).
Polymer flooding has generally been applied in light or medium gravity oil and even today, standard industry screening criteria limit its use to viscosities up to 150cp only. Pelican Lake is the first successful application of polymer flooding in much higher viscosity oil (1,000-2,500cp) and as such, it opens a new avenue for the development of heavy oil resources that are not accessible to thermal methods.
Water-based Enhanced Oil Recovery (EOR) technologies such as Low Salinity Flooding (LSF), Chemical EOR (CEOR), and steam-flooding have been growing in popularity over the years, and are generating new opportunities for the water treatment sector as a result. Water treatment technologies have the unique capability to address equipment and system requirements which are characteristic of EOR projects. However, these technologies typically have little to no history of application in the upstream oil and gas industry. This limited level of experience may impact EOR project budgets and schedules, particularly in offshore applications where weight and footprint availability are of critical value.
In Southeast Asia, two offshore projects are investigating the use of customized water to maximize oil recovery in CEOR applications. In the first project, two CEOR programs consisting of vastly different water quality cocktails are under consideration, one of which incorporates produced water into its water source. In the second project, injection water quality with an ultra-low hardness level is desired, in order to prevent potential precipitation in the reservoir. In both cases, water treatment infrastructure must be capable not only of producing the intended injection water quality, but it must do so consistently in response to potential changes in the quality of the source water used.
This paper describes the results of pilot testing of two typical water treatment technologies, Reverse Osmosis (RO) and unique nanofiltration membranes, to produce a variety of injection water chemistries for CEOR and LSF applications. These applications include ultra-low hardness, high salinity; and low hardness, low salinity injection water. The testing confirms the ability of new water treatment technologies to solve challenging issues that arise in EOR applications, particularly those in offshore applications that must respond to varying needs of reservoirs and footprint/weight limitations.
Miscible/Immiscible carbon dioxide injection is considered as one of the most effective technology to improve oil recovery from complicated formations. Main factor restraining wide application of this technology is its dependence on natural CO2 sources, transportation of CO2, breakthrough of CO2 to production wells, corrosion of well and field equipment, safety and environmental problems etc. However, in-situ carbon dioxide generation technology is eliminating CO2 negative impact and strong control of the process.
The EOR mechanism of proposal technology is described as follows: acid and exothermic chemical reaction function relieve deep reservoir damage, micronucleus systems formed possess abnormal reological properties allowing to improve water flooding efficiency, CO2 as a super-critical fluid decreases oil viscosity and gas form CO2 reaches such place in the formation where not many solvents can enter to, foamed gas-liquid system creates additional resistance for water injected after gas-liquid system, surfactant formed decreases interfacial tension in oil-water contact, and CO2 solved in oil increases oil volume what affects on displacement of residual oil.
Lab research shows that proposed technology can decrease injection pressure of damaged core by 11.7MPa, gas generation amount and oil volume increasing rate increases with temperature and system concentration increasing, oil volume increasing rate and oil viscosity reducing rate increasing with oil viscosity increasing. Under the conditions of 60 degrees Celsius, 10MPa, 2010mPa.s, it can increase oil volume by 25%, reduce oil viscosity by 52.7%, improve recovery efficiency by 7.6%~14.2%.
Field pilot tests were conducted in seven injection wells in China Bohai offshore oilfield in 2009~2010. All the wells present significant effect of decreasing injection pressure and increasing injection rate, average decreasing pressure by 3.2MPa, average increasing injection rate of single well by 22118m3, cumulative increasing injection rate by 154827m3, cumulative increasing oil of around production wells by 29000m3. Field pilot tests shows that proposed technology can be applied in a wide range of geological conditions, and be the key to recovering huge amount of oil from highly watered, depleted, heterogeneous and other type of so called hard-to-recover oil reserves.
Sorop, Tiberiu Gabriel (Shell Global Solutions International) | Suijkerbuijk, Bart M.J.M. (Shell Global Solutions International) | Masalmeh, Shehadeh K (Shell Technology Oman) | Looijer, Mark T. (Shell Global Solutions International) | Parker, Andrew R (Shell Global Solutions International) | Dindoruk, Deniz M (Shell Exploration & Production Co) | Goodyear, Stephen Geoffrey (Shell E&P UK) | Al-Qarshubi, Ibrahim S.M. (Shell Global Solutions International)
Low Salinity Waterflooding (LSF) is an emerging IOR/EOR technology that can improve oil recovery efficiency by lowering the injection water salinity. Field scale incremental oil recoveries are estimated to be up to 6% STOIIP. Being a natural extension of conventional waterflooding (WF), LSF is easier to implement than other EOR methods. However, the processes of screening, designing and executing LSF projects require an increased operator competence and management focus compared to conventional waterflooding. This paper discusses the practical aspects of deploying LSF in fields, focusing on the maturation stages, while highlighting the key success factors.
LSF deployment starts with a portfolio screening against specific surface and subsurface screening criteria to prioritize opportunities. Next, the identified opportunities are run through reservoir conditions SCAL tests to quantify the LSF benefits, while de-risking the potential for any injectivity loss due to clay swelling or deflocculation. Standardized LSF SCAL protocols have been incorporated into the general WF guidelines, so that any suitable new WF project conducts LSF SCAL. For mature waterfloods, this SCAL program provides additional reservoir condition relative permeability data, enabling operating units to optimize well and reservoir management (WRM). The next steps in the process are production forecasting, facilities design, and project economics for the LSF opportunity. The multidisciplinary nature of LSF deployment requires integrated (sub)surface technology teams closely collaborating with R&D and asset teams. The standardization of the facilities design, including cost models, can significantly accelerate the deployment effort.
In Shell, LSF is currently at different stages of deployment around the world and across the whole spectrum of WF projects, from the rejuvenation of brown fields to green field developments (offshore and onshore). The LSF deployment effort is combined with the screening of other EOR technologies, to identify where LSF may be able to unlock additional value by creating the appropriate conditions for subsequent chemical flooding.
Castro, Ruben Hernan (ECOPETROL, S.A.) | Maya, Gustavo Adolfo (Ecopetrol SA) | Sandoval, Jorge (Ecopetrol SA) | Leon, Juan Manuel (Ecopetrol SA) | Zapata, Jose Francisco (Ecopetrol SA) | Lobo, Adriano (Ecopetrol SA) | Villadiego, Darwin Oswaldo (ECOPETROL, S.A.) | Perdomo, Luis Carlos (ECOPETROL, S.A.) | Cabrera, Fernando Ariel (TIORCO, Inc.) | Izadi, Mehdi (TIORCO, Inc.) | Romero, Jorge Luis (TIORCO Inc) | Norman, Charles (TIORCO, Inc.) | Manrique, Eduardo Jose (TIORCO, Inc.)
Dina Cretaceous Field is located in the Upper Magdalena Valley (UMV) Basin, Colombia. Dina Field operated by ECOPETROL S.A. (discovered, 1969) started peripheral water in 1985. Based on high water cuts (96%) and recovery factors of 32%, comprehensive enhanced oil recovery (EOR), screening evaluation began late 2009, identified Colloidal Dispersion Gel (CDG) as an optimum EOR method for the field.
This paper summarizes Dina CDG project from the laboratory to the field evaluation. Laboratory studies include basic fluid/fluid evaluation, static adsorption, CDG formulations, slimtube, and coreflood tests. Pilot area selection was based on a comprehensive reservoir and injection/production data analysis, water management, well integrity, among other factors. Pilot design was based on detailed numerical simulations using sector and full field models. CDG pilot design also considered water handling limitations and potential injectivity constraints due to the narrow margin of maximum injection and reservoir pressures, combined with low reservoir permeability (50 to 200 mD).
Peripheral CDG pilot included one injector and three producers. CDG injection began in June 2011 and as of September 2012, approximately 437,000 bbl of CDG have been injected (5% of pilot PV). CDG injection strategy considered a fix polymer concentration of 400 ppm and a variable polymer/crosslinker ratio ranging from 40:1 to 80:1; to control maximum injection pressure. Field results showed an important increase in oil recoveries (oil productivity up to 300%) and reduction of water cut decrease (10%). After 16 months, no polymer had been produced in offset producers. Main operating challenges experienced during the pilot project included; the improvement in water quality and its impact on CDG injectivity which will also be described.
This study provides guidance to successfully design, implement, and evaluate CDG pilot projects and other potential chemical EOR technologies in waterflooded reservoirs. Lessons learned during pilot testing contributed to defining pilot expansion strategies supported by an integrated decision-risk management approach.
Zheng, Frank (Cameron) | Quiroga, Pilar (Cameron) | Zaouk, Moshen (Cameron) | Blackman, Nick (Cameron) | Mandewalkar, Pavan (Cameron) | Sams, Gary W. (Cameron) | Sellman, Erik L (Cameron) | Gopeesingh, Cameron Horace (Cenovus Energy) | Morgan, Justin (Cenovus Energy)
Polymer flood using partially hydrolyzed polyacrylamide (HPAM) has been proven to be an effective method to increase oil recovery. However, when HPAM breaks through the reservoir and shows up in the produced fluids, it brings unique emulsion
characteristics and challenges to the separation processes. Operators have experienced frequent equipment failures on heat exchangers and heating elements. Traditional oil dehydration uses mechanical heater treaters which rely on elevated
temperature to improve the settling of the dispersed water phase. In HPAM flood, the fire tubes in these mechanical heater treaters have become problematic and experienced repetitive failures. Electrostatic technology uses the response to the
electrostatic field by the polar dispersed water phase to enhance the water settling. Electrostatic technology has been a proven technology for oil dehydration and desalting for water flood and other recovery methods such as Steam Assisted Gravity
Drainage (SAGD), but not widely used in HPAM flood. A joint study was conducted between Cameron and Cenovus to evaluate the electrostatic dehydration of the heavy oil from HPAM flood. The results of the study indicate that, due to the presence of HPAM in water, the electrostatic dehydration of the wet oil from HPAM flood demonstrates some unique characteristics. Electrostatic dehydrators can achieve about 300% of the capacity of mechanical heater treaters. Proper equipment and process designs are important to reduce the equipment failures. The results of the study offer a more effective oil dehydration technology to the HPAM flood producers. The benefits of electrostatic dehydration can be especially valuable for the offshore implementation of HPAM flood due to the space and weight savings.
With the conventional decline in oil production from wells in the United States, additional sources of crude oil are required. One option supported by high oil prices is the application of enhanced oil recovery and advanced secondary recovery technologies to the currently producing wells. The U.S. onshore lower 48 crude oil in-place resource are vast. The question is how much of the oil can be produced using currently available technologies.
In order to answer that question, a detailed analysis was conducted in which the potential technical and economic production was estimated for several commonly used technologies. These include EOR technologies such as carbon dioxide flooding, polymer flooding, and steam flooding, as well as a variety of advanced secondary recovery technologies.
This analysis was conducted using screening and analytic tools which identify the recovery processes which are applicable to each reservoir in the onshore lower 48 and estimate the technical production from each reservoir. In addition, a newly developed economic model was used to estimate the technical and economic production which could be realized.
The results, data and opinions presented in this paper are those of the authors and not the companies with which they currently work. This paper describes the screening criteria which were used to determine the applicable technologies. The paper also describes the analytical tools used to estimate the technical and economic production for each of the assessed technologies.
Finally, the paper details the production levels which could be realized under a variety of technical and economic scenarios.
U.S. oil resources are distributed among some 70 known oil producing basins including those of the Lower-48 states, those in Alaska, and those in U.S. offshore waters. U.S. known original onshore oil resources are vast. Proved reserves peaked in 1970 at 39 billion barrels and declined to about 20 billion barrels as of the end of 2009. Approximately 13 billion barrels of these proved reserves are located in the Lower-48 states in onshore reservoirs1.
To date, cumulative production from known U.S. reservoirs has totaled more than 194 billion barrels, making the U.S. among the most efficient oil producers in the world. Still, billions of barrels remain as a target for potential recovery by various means.
The United States is currently producing a substantial percentage of its oil using EOR processes. As reported by The Oil and Gas Journa12 in 2010, the daily EOR production was 663,431 barrels per day from 193 projects. Of this production, the most substantial components, as seen in Figure 1, are CO2
miscible flooding and thermal flooding. These two processes make up 82% of the production and 80% of the existing EOR projects in the United States.
Zwaan, Marcel (Shell Intl E&P Co) | Hartmans, Robert (PDO) | Saluja, Jasmeet Singh (Shell Intl E&P Co) | Schoofs, Stan (Petroleum Development of Oman) | Rocco, Guillermo (PDO) | Adawi, Rashid (PDO) | Saadi, Faisal (Shell Intl E&P Co) | Lopez, Jorge L. (Shell Global Solutions International) | Ita, Joel (Shell Intl E&P Co) | Mahani, Hassan (Shell Intl E&P BV) | Qiu, Yuan (Petroleum Development of Oman) | Rehling, Johannes
PDO has implemented Enhanced Oil Recovery (EOR) methods including thermal, chemical and miscible gas injection projects in several fields. In the initial phase of these EOR projects, well and reservoir surveillance is key to increase the understanding of the effectiveness of the EOR processes in the various reservoirs. Well-planned and executed reservoir surveillance has proven in the past to add significantly to the production and ultimate recovery from reservoirs.
Because of progress in technology in areas of data acquisition, processing and modeling techniques, well and reservoir surveillance data are increasingly used to optimize EOR processes. However, the interpretation of all data and integration into well and reservoir management workflows is still challenging. This paper describes the ongoing development of workflows for the interpretation, modeling and integration of surveillance data in three EOR projects.
The surveillance methods include geomechanical modeling, thermal reservoir modeling and monitoring through timelapse seismic, surface deformation, microseismic, temperature, pressure and saturation logging.
Carbon capture for enhanced oil recovery is a proven technology that holds the promise of increasing oil reserves, reducing greenhouse gas (GHG) emissions, diminish the concerns associated with the release of cocktail gases from gas flaring and reduce hostility in host communities. In this work, we considered the Okota/Okpoputa field in Offshore Niger Delta and covered areas of interest such as the post combustion capture using monoethanolamine (MEA), prognosis of storage site, increase production pressure, economics of the capture and assessment of the risk of leakage. With about 80million tonnes of CO2 captured annually from flared flue gas, the CO2-enhanced oil recovery will yield 20-40% Original Oil in Place (OOIIP), and this will translate to a savings of $ 474,500,000 excluding commercial sales of CO2.
Keywords: Enhanced oil recovery, Prognosis of storage site, greenhouse gas emission, Niger Delta
Selecting the optimum combination of enhanced oil recovery (EOR) technologies is a critical activity during preparation of a successful business plan. This is usually accomplished by using protocols with technical parameters at reservoir formation levels from which candidates EOR technologies are screened and then
subject to investment and risk assessment evaluation for final decision by management.
The previous approach very often misses the effect of operational expenditures, wearing and failure related downtime and learning curve during pilot testing on oil recovery efficiency and EOR economics which is usually expressed in terms of net present value.
This paper proposes an alternate simplified approach using an acceptable representation of life cycle phases of natural and physical asset components functioning as a system of assets for a particular subject reservoir. We introduce a taxonomic solution to help in classifying candidates EOR technologies. Four major functional indices are used for handling uncertainties and risks using data from analogs for defined scenarios in the subject reservoir: 1-Accesability) Footprint effects for constructing and operating physical assets (wells and surface infrastructure), 2- Contactability) Volume of resources contacted from a surface
location, 3-Produceability) Volume of producible resources from drainage area to surface and 4- Effectiveness) Combined effect of availability, reliability, maintainability y and capability in efficiency of oil recovery.
The four major indices are cross referenced with life cycle cost (LCC) and estimated ultimate recovery (EUR) using Hubbert peak oil theory and the Petroleum Resources Management System classification for resources and reserves. Uncertainties and risks are modeled with Monte Carlo simulation (MCS) or
Systems Dynamics (SD) depending on the complexity of the system of assets.
We present examples using synthetic data to illustrate the method.
This approach is worth using during EOR project definition and planning as an alternate to complex data hungry methods.
Most of the world's oil is found in a small number of ‘petroleum systems'. A petroleum system is an area where oil or gas was created in a single ‘pod' of source rock which has migrated upwards and become trapped in a number of oil and gas fields or assets. Not only is oil concentrated mainly in very few provinces
and petroleum systems within these provinces, but within a given petroleum system, it is concentrated inside very few fields (1).
Therefore it is a fact that the oil and gas industry deals with the management of a finite, depletable or exhaustible resource, i.e., hydrocarbon resources.
The production of any hydrocarbon resources from a field or asset has a gradual increase (development phase) reaching a maximum output (peak), then a plateau and a decline (maturity) when the output will fall irreversibly down to an economic limit where the decision of abandonment needs to be addressed. Many fields combine together, placing a small number of large fields near the beginning and a large number of small fields at the end produce something like a bell curve as shown in Figure 1. This bell curve is also called Hubbert Peak Curve after the geophysicist M.King Hubbert who predicted in 1956 (2) (3) that the oil production for the lower 48 states of USA would peak between 1965 and 1970.
Hubbert recognized that the depletion of any finite resource starts with production at zero and that in the initial stages, the rate of oil production tends to increase exponentially with time. However, physical limits prevent production to increase at the same rate because finite resources cannot keep up the increasing production rate forever. At the end of the life cycle the total volume under the bell curve will be the ultimate recovery.
The magic of Hubbert´s approach was the use of a proxy model known as the logistic equation, developed by the Belgian statistician Pierre Verhulst which was an improvement over the Malthusian model (4). In 1982, Hubbert refers to the original Verhulst papers and goes through a complete derivation of the
mathematics involved in his model. The details and implications of the use of proxies for modeling management of finite resources is beyond the scope of this paper, however we address the issue from an economic perspective later in the paper. For now we can state that Hubbert Peak curve can be used to
empirically approximate the full cycle of the growth, peaking, and subsequent decline to zero of the production of a finite, nonrenewable resource and estimate ultimate recovery.