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.
Two commercial Alkali Surfactant Polymer (ASP) floods became operational in the Taber area of Alberta, Canada in 2006 and 2008. Both of these floods used NaOH as the Alkali. Throughout the course of both projects extreme scale deposition was observed in downhole production equipment, gathering systems, and in the production facility. Early in the life of the floods the scale composition was predominantly calcium carbonate, however over time the scale changed to consist of greater amounts of amorphous silicate.
Scale inhibition and remediation strategies have been developed which include a comprehensive monitoring program, chemical scale inhibition, and mechanical scale prevention techniques. As a result of the large amount of data gathered, models were created to predict scale severity, content, and develop specific mitigation plans. Although clear field wide scaling trends can be identified over the life of these projects, scale mitigation strategies still need to be customized for each well.
Although scale remains an operational challenge in these fields, with proper mitigation procedures it can be managed. This report documents the success in reducing the impact of the scale problem and slowing the depositional rate. When designing ASP floods it is important to plan for scale deposition and be proactive on scale mitigation.
This paper illustrates an innovative field-scale application of injecting condensate gas and recycling gas in Jake field, Sudan. This field has two production series, namely AG condensate gas pools and Bentiu oil pool from bottom to up, with the former 3520 ft. below the Bentiu reservoir and 1695 psi of initial reservoir pressure difference. Bentiu pool of Jake field is a medium crude oil (29 API) pool with strong aquifer support. Well productivity was 500 BOPD. Operator intended to inject high-pressure condensate gas into Bentiu pool to increase field output, whereas was confronted with following challenges: 1) injection of condensate gas in an easy-to-operate wellbore configuration; 2) optimization of injection parameters to achieve highest output; 3) suppress aquifer water breakthrough.
Field scale application had been optimized and implemented since 2010:1) High-pressure condensate gas had been injected into two updip crest Bentiu wells in the same well bore, following a huff-and-puff process, well output amounted 4,000 to 13,800 BOPD under natural flow; 2) 1/4 recycling gas volume from compressors was re-injected into 12 downdip wells at controllable pressure to avoid early water breakthrough; 3) The remaining recycling gas was utilized to gas-lift other five updip wells.
Oil producers were reduced from 19 to 7 comparing to original field development plan, while oil rate ascended from 22,000 to 30,000 BOPD, with watercut dropping to 7% from 15%, achieving a high offtake rate of 6%. Reservoir simulation indicated ultimate recovery factor is expected to be over 50% with such full-field gas injection.
Conclusions drawn from field scale injection of condensate gas and recycling gas were as follows:1) condensate gas injection in the same well bore was technically innovative and operationally robust; 2) recycled gas injection into downdip wells helped detain water breakthrough; 3) field scale application had evidenced outstanding success with high output and high offtake rate.
Prior to any EOR application, quantifying the remaining oil saturation (ROS) after water flood is critical in order to establish the target oil for a potential EOR scheme. The most widely available datasets for quantifying ROS are from the saturation logs such as resistivity logs from infill wells and pulsed neutron capture (PNC) logs from cased wells. However, the interpretation of these logs generally requires prior knowledge of water salinity. In most water flood projects, the injected water is different from the formation water, and the salinity is unknown in the water flooded zones. Logging tools for saturations without prior knowledge of salinity, such as the C/O log, also have limitations.
The current practice to overcome this problem is to apply one or more of the following techniques:
• Chemical tracer
• Sponge coring, pressurized coring, etc.
However, these techniques are relatively expensive and time-consuming. They cannot be used routinely field wide as a reservoir surveillance tool.
In this paper, we present a methodology to reduce the uncertainties in saturation logs within the context of reservoir model history-matching. In addition to matching pressure and water cut, the new methodology seeks to match the produced water chemistry too (with formation water and injection water chemistry as inputs). This is due to the recent advance of reservoir simulations that can model reservoir water composition changes by considering geochemical reactions of injection waters, formation brine, and reservoir minerals. With this new simulation capability, resistivity and sigma values per grid block are computed as part of the simulation, thus pseudo-logs of total resistivity and neutron capture cross section (S) can be generated as part of the simulation. This enables direct history-matching of the measured log signals.
For an EOR project, the implication of this new simulation methodology is to encourage the frequent sampling and analysis of injection and produced water as part of the reservoir surveillance, and run resistivity and/or S logs to monitor saturation changes even when injection water is significantly different from formation water.
Viscous oils have adverse mobility that causes production to decline rapidly following a period of primary recovery. Traditionally, enhanced oil recovery (EOR) for this kind of oil has mostly relied on reducing viscosity and increasing mobility using thermal methods or miscible gas injection. However, in some cases—for example, deep reservoirs, thin sands, or restricted offshore applications—these methods might not be feasible. This paper discusses published field studies using polymer flooding EOR for viscous oil and provides recommendations for its applicability.
In countries with reservoirs that present challenges for use of traditional EOR methods, such as Canada, China, and Suriname, polymer flooding has been field tested as a reliable oil-sweeping method while minimizing the risk of high water cut. With oil viscosities at reservoir conditions up to 5000 cp and reasonable economic conditions, polymer flooding has been shown to be an attractive EOR alternative. The study cases presented show that polymer concentrations need only be between 800 to 1,500 ppm to ensure successful results.
Concerns about low or poor injectivity of polymers are being overcome using fracturing and horizontal wells, while high-value, limited-space challenges on offshore platforms are being addressed through modular and minimized installations. Additionally, most conventional waterflood monitoring and surveillance techniques are also applicable to polymer floods, while polymer use in backflow tests and as a tracer has also been proposed.
This study's projection shows a 90% probability of positive net present value (NPV) under broad ranges of uncertainty for oil price, recovery factor (RF), capital expenditures (CAPEX), and operational expenditures (OPEX). The results of this paper show that polymer flooding presents a clear and feasible alternative for increasing the RF of viscous oil. To this end, a detailed study is provided of its advantages and the reservoir condition range of applicability.
Trigos, Becerra Erika Margarita (Ecopetrol) | Rueda, Neira Silvis Fernanda (Natfrac) | Rodriguez, Paredes Edwin (Ecopetrol SA) | Rivera de la Ossa, Juan Eduardo (Ecopetrol SA) | Naranjo Suarez, Carlos Eduardo (Ecopetrol SA)
A number of publications (Valbuena, 2009; Haroun, 2008; Schoofs, 2010; Meshal, 2009) have shown the application and also the relevance of heat management in steamflooding projects. This concept is based on the understanding of the process phases and the identification of energy requirements at each phase, which leads to avoid the loss of energy. Based on field experience at Duri (Ziegler, 1993) and Kern River (Gael, 1994) is easy to recognize that the best strategy varies according to the particular characteristics of the reservoir.
In Colombia there are some reservoirs with presence of interbedded shale and a long history of steam cycles stimulation, thereby research using numerical simulation to determine the best scenarios for steam flooding implementation was conducted. A deep analysis taking into consideration, injection rate, well spacing, selective injection strings technology, partial interval completion as a strategy of delaying the steam breakthrough in the production well and finally, strategies of heat management such as periodic reduction of the injection rate and scheduled shutdown of injection well were evaluated.
The final results showed eight possible implementation scenarios that later will be compared from an economic perspective to identify the ideal scenario for field implementation. Simulation results showed that high injection rate (700 BWE/day-well) in patterns of 2.5 acres produced the highest incremental production, yielding an accumulation of about two million of oil barrels over a period of 10 years. Unfortunately, this production is associated with a high cumulative steam oil ratio (cSOR) near to 13. The best strategy to reduce cSOR was the periodic reduction of injection rate reaching a cSOR ratio of 11. The time of evaluation of the project was identified as one of the most influential parameters for the establishment of the heat management strategy.
In May 2006, the Warner Mannville B ASP flood was the first field wide ASP flood implemented in Canada. The objective was to successfully implement a commercially viable ASP flood. In this project produced water is treated and reinjected into the reservoir. As of December 2012, an incremental 420 103m3 (2.65 million bbl) of oil has been recovered with an expected total incremental recovery of 777 103m3 (4.89 million bbl), which represents 11.1% of the OOIP. In October 2008, after 0.35 pore volume of ASP injection, the project moved into the Polymer only injection phase. Polymer injection will continue as long as is economically feasible.
A comprehensive monitoring and testing program was implemented to evaluate flood response and performance. This allowed for the optimization of the flood through continuous adjustment to flow rates and led to successful infill drilling locations.
Many challenges have been encountered during this project, including: silicate scale production, treating issues related to the water quality of the recycled injection water, and loss of injectivity in many injection wells.
The challenges were overcome and it has been an economic success with a cumulative positive cashflow within 5 years. The results of this flood have led to the implementation of an additional four floods. The lessons learned from this project have improved numerous aspects of how future floods are designed and implemented.
EOR technology has been applied on many projects globally with variable success. It shows great potential for offshore heavy oil with oil recovery low in life span of platform (general less than 30% by water flooding). About 60-70% oil is remained in the formation after water flooding, and for offshore heavy oil reservoir, more oil (about 80%) is remained by the end of the platform life.  It becomes more important to achive high recovery before abandoning the platform and the oilfields with lots of oil left in reservoir. With recovery increasment of 5-10% by EOR methods, the reserve will increase greatly, which means an order of magnitude of hundreds of million-tons oilfield is discovered without increase any exploration investment.
Surfactant-polymer (SP) flooding was a potential enhanced oil recovery (EOR) technology that was more powerful than the polymer flooding. And it was test or applied successfully in some high or extra-high WCT onshore oilfields of Shengli oilfields (SINOPEC), Daqing oilfields (CNPC) in china. The paper presents a filed EOR test case of offshore heavy oilfield oilfield by SP.
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.
Zhu, Youyi (Research Inst. Petr. Expl/Dev) | Jian, Guoqing (Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Weidong (Research Institute of Petroleum Exploration and Development, CNPC) | Cheng, Lijing (Oil Production Engineering Research Institute of Dagang Oilfield) | Hou, Qingfeng (Research Institute of Petroleum Exploration and Development, CNPC) | Li, Jianguo (Research Institute of Petroleum Exploration and Development, CNPC)
Surfactant-Polymer (SP) flooding has attracted lots of attention among chemical combination flooding researchers in recent years. Pilot tests of SP flooding in China were introduced and key factors influencing the performance of pilot tests were analyzed in this paper. Main technological problems occurred in pilot tests were indicated. Suggestions concerning technology improvement and development were given.
About ten SP flooding pilot tests were carried out in China since 2003. These target reservoirs were characterized with high permeability and low permeability sandstone, conglomerate, and high temperature and high salinity ones respectively. At present, the performance of SP flooding pilot tests in Gudong Block 6 and Gudong Block 7 of Shengli oilfield have shown good enhanced oil recovery (EOR) effect. It confirmed SP flooding could improve both of oil displacing efficiency and sweep efficiency and EOR ability for SP flooding is better than that of polymer flooding. EOR effect of SP flooding can be reflected from the following two aspects. Firstly, with SP slug injecting, the pressure of injection well increased and fluid entry profile was adjusted. The performance of profile control was favorable. Secondly, ultralow interfacial tension could be achieved and residual oil was displaced significantly. SP flooding showed stronger ability in decreasing water cut and increasing oil production than polymer flooding. The production history data showed that main factors influencing EOR were the corresponding relationship between injection wells and production wells, the chemical formula properties and the injection amount of SP system. The favorable oil production was obtained when the corresponding relationship between injection wells and production wells was good. The quality stability of SP formula could influence the flooding EOR performance greatly. Small injection slug size of chemical system would lead low EOR level.
The key technologies which should be improved and optimized for SP flooding are displacing agent quality, formula system stability, slug design, well pattern and so on.