Determination of swept volume is important for evaluation of a thermal project. Thermal well testing offers a simple method to estimate the steam zone properties using pressure falloff tests. A composite reservoir model is assumed with two regions of highly contrasting fluid mobilities and the flood front as an impermeable boundary. The swept zone therefore acts as a closed reservoir and pressure response is characterized by pseudo steady state behavior.
Most of the previous studies have considered vertical wells because of the simpler method of well test analysis compared to horizontal wells. However, a steam assisted gravity drainage (SAGD) process using horizontal well pairs is a promising technique in heavy oil recovery.
The applicability of thermal well test analysis in estimating the swept zone properties for vertical and horizontal wells was thoroughly investigated in this study. A thermal simulator was used to simulate pressure falloff tests. The generated pressure data were then analyzed to calculate swept volume and reservoir parameters. Properties of an Athabasca heavy oil sample, measured in the lab, were used as input for numerical simulation purposes.
Results of this work show good agreement between the calculated and simulated values of swept volume, swept zone permeability and skin factor for both vertical and horizontal wells. Estimations depend on the vertical position of the pressure gauge. Effects of gravity, swept region shape, dip, steam quality, steam injection rate, injection time, permeability anisotropy and gridblock density on the results were also investigated. Higher injection rates and longer injection times lead to poorer estimates of the swept volume because of a more irregular shape of the swept region and the possibility of earlier breakthrough. Vertical and lateral distances between the horizontal injector and producer affect the estimation of swept volume. Isotropy and grid refinement do not necessarily improve the estimations.
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.
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.
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.
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.
Choudhuri, Biswajit (Petroleum Development Oman) | Kalbani, Ali (Petroleum Development Oman) | Cherukupalli, Pradeep Kumar (Petroleum Development Oman) | Ravula, Chakravarthi V. (Petroleum Development Oman) | Hashmi, Khalid (Petroleum Development Oman) | Jaspers, Henri F (Petroleum Development Oman)
In viscous oil reservoirs, Polymer flooding is often used to improve oil recovery either after a short period of waterflooding or as a tertiary recovery process following extensive period of waterflood. After six years of water flooding in a major reservoir in Sultanate of Oman having viscous oil (90cp), a field development plan was developed to implement polymer flooding in this reservoir with anticipated incremental oil recovery of around 10% over and above that of waterflood. Necessary facilities were constructed, injection and production wells were drilled, completed, converted and the polymer flood project was initiated and ongoing since the last three years through 27 polymer injectors. By implementing proactive Well and Reservoir Management (WRM) strategies, the actual oil recoveries have been better than predicted levels so far. It is demonstrated here that proactive well and reservoir management through proper well and reservoir surveillance and dynamic adjustment of injection and production rates play a very important role in improving the performance of polymer floods as in waterfloods.
Well and Reservoir Management (WRM) principles in case of a polymer flood are similar to that of high mobility ratio waterfloods with some additional aspects that are specific to a polymer flood scenario. Polymer chemical costs, its higher viscosity and non Newtonian fluid flow behavior all create unique conditions that are nonexistent in normal waterfloods. This, in turn, dictates the strategies and methods employed to optimize polymer flood performance. This paper details successful implementation of proactive WRM strategy that has played a key role in sustaining production from this polymer flood field to date. It describes the pattern management processes to optimize pattern wise polymer injection and oil recoveries, conformance control measures implemented to increase sweep and oil recovery, innovative surveillance techniques to monitor fracture growth in polymer injection wells and for evaluation and optimization of production/injection profiles. Production wells and facilities issues arising from polymer breakthrough are being addressed to mitigate any adverse effects.
Thakuria, Chandan (Petroleum Development Oman) | Al-Amri, Mohsin Saud (Petroleum Development Oman) | Al-Saqri, Kawthar Ahmed (Petroleum Development Oman) | Jaspers, Henri F (Petroleum Development Oman) | Al-Hashmi, Khalid Hamad (Petroleum Development Oman) | Zuhaimi, Khalid (Petroleum Development of Oman)
The first field scale Polymer flood project in the Middle East region is being implemented in an oil field of Sultanate of Oman from early 2010. The oil field discussed here containing viscous oil (90 cp) was discovered in 1956 and is located in eastern part of South Oman Salt basin. First commercial production started in 1980 from this field. The field has gone through different development phases in its 30 years of history prior starting tertiary recovery phase by polymer flooding.
This field scales Polymer flood project comprising 27 patterns as Phase-1 covers about one third of the total field IOIP (initial oil in place). It is worth mentioning that whole field is under water flooding and water injection was going on prior to initiation of Polymer flood in all these 27 injectors. Further extension in phases to full field polymer flooding is under evaluation.
Till now this Polymer flood project has successfully completed 3 years of good performance contributing to significant oil gain. This paper describes briefly about the principles involved in polymer flooding, planning of this polymer flood project, field implementation and field examples of polymer response. In addition, a few practical aspects of managing key issues in polymer flooding like- fracture growth in injectors, shear degradation of polymer solution, pattern conformance and back produced polymer has been covered in this paper.
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.
Liu, Xincang (No.4 Oil Production Company of Daqing Oilfield) | Zhang, Dong (No.4 Oil Production Company of Daqing Oilfield) | Ding, Jian (No.4 Oil Production Company of Daqing Oilfield) | Ran, Fajiang (No.4 Oil Production Company of Daqing Oilfield) | Zhao, Mingchuan (No.4 Oil Production Company of Daqing Oilfield) | Li, Shiyong (No.4 Oil Production Company of Daqing Oilfield)
It's very important to evaluate layered producing performances at different stages in the course of oilfield development, but due to limitations of monitoring well conditions and logging expenses, it is difficult to comprehensively and systematicly monitor all the producers, and this will bring troubles to adjustments and evaluations during oil field development. To solve this problem, the Chromatographic Fingerprint technique is introduced to monitor layered producing performances in test area F which has four target zones in Daqing Oilfied. After response of alkaline-surfactant-polymer (ASP) flooding, screw pumps are adopted to some producers to minimize scaling in F area where producing profile surveys for annulus wells aren't adaptable to mornitor the layed producing status. Pre-test in lab shows that the Chromatographic Fingerprint technique is feasible for the four individual test zones for there are distinct chromatographic fingerprint differences, and ASP injected solution has less influences on fingerprints. A fuzzy interpretation template has been successfully set up for commingled 4-6 layers production numerical simulation by using EPB neural network model, and relative errors can be controlled below 10%. The technique has been applied to the producers for 180 times. In-situ test results are stable and correspond to the static information of lays. It indicates that the Chromatographic Fingerprint technique is suitable for monitoring individual zone producing performances of ASP flooding. The results from the fuzzy interpretation template have provided powerful data to re-recognize the connectivity of heterogeneous reservoir between injectors and producers. It can be applied to producers whose producing intervals belong to the fuzzy interpretation template. The oil production proportion of per lay's can be easily achieved after the sample from the well fluid is analysed with chromatography and calculated with the fuzzy interpretation template. The technique has proved to be economical and it is not astricted by well conditions, so it can play an important role to guide development programs' adjustments and evaluations in oilfields.
Tewari, Raj Deo (Petronas Carigali Sdn Bhd) | Bui, Thang (Schlumberger) | Sedaralit, Mohd Faizal (PETRONAS) | Kittrell, Chuck M (Schlumberger IPM-RMG) | Riyadi, Slamet (Petronas Carigali Sdn Bhd) | Rahman, Hibatur (Petronas Carigali Sdn Bhd)
This paper discusses about the optimization study of applying the enhanced oil recovery technique in a multilayered mature offshore oilfield. This field is located at water depth 65-70 m. There is significant variation in rock and fluid properties from top to bottom in the field. Upper sands are highly porous and permeable, poorly consolidated and hold viscous oil.Whereas lower formations are fully consolidated and contain lighter oil with a high GOR. Oil in most of these reservoirs are under- saturated. The field is under primary production for the last 30 years with appropriate sand control and artificial lift measures.
Production performance indicates that current development strategy and practices will yield a moderate recovery lower than average recovery in Malay basin fields. A comprehensive reservoir characterization has been carried out to capture the reservoir heterogeneity and multiple realizations of reservoir properties distribution have been used to understand the major uncertainties of the field. Performance analysis combined with simulation modeling identified a suitable EOR application with appropriate well spacing to maximize the drainage of undrained oil while improving the sweep from partially drained portions of the reservoirs. Since the field is in mature stage of the producing life, delaying the enhanced oil recovery application may not be a sound strategy for maximizing the recovery. Improving the well density and applying EOR should be part of a redevelopment strategy. Exhausting the option of primary production and then embarking on enhanced oil recovery application may be detrimental in maximizing the value of the asset. Water alternating gas injection (WAG) in immiscible mode has been firmed up for improving the oil recovery from this offshore field. The improvement in recovery due to WAG injection is attributed to contact of the upswept zones and modification of residual oil saturations and targeting the attic oil. The combination of water and gas injection in WAG improves the microscopic displacement efficiency and increases the mobile oil saturation. Hysteretic effects which change saturation paths, due to sequential injection of water and gas, additionally improve the recovery. Thus the combined effect of water and gas injection in improving the recovery in WAG is better as compared to separate gas or water injection. Three phase flow (oil, water and gas) is better in displacing the residual oil compared to two phase flow water and oil or gas and oil.
One of the major challenges envisaged in the application of EOR in a multilayered reservoir with very large thickness is poor conformance of injectants. This is critical for the success of the process. Parameters which are critical for impacting the WAG enhanced oil recovery process are studied thoroughly. The study suggests that improving the well spacing and proper injection volume with good conformance control and timely initiation of the process would result into an improvement of recovery factor on the order of 8-10%. The paper also discusses the laboratory results of mechanism of formation damage with water injection and rock-fluid interaction.