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Polymer flooding is a mature Enhanced Oil Recovery process which is used worldwide in many large- scale field expansions. Encouraged by these positive results, operators are still looking at applying the process in new fields even in the context of low oil prices and are evaluating its feasibility in more challenging reservoir conditions: high salinity, high hardness and high temperature. Several solutions have been proposed to overcome the limitations of the conventional hydrolyzed polyacrylamide (HPAM) in these types of challenging environments: biopolymers such as xanthan or scleroglucan, associative polymers, or co- or ter-polymers combining acrylamide with monomers such as ATBS or NVP. Each of these solutions has its advantages and disadvantages, which are not always clear for practicing engineers. Moreover, it is always interesting to study past field experience to confront theory with practice. This is what this paper proposes to do.
The paper will first review the limits of conventional HPAM and other polymers that have been proposed for more challenging reservoir conditions. But more than that, it will focus on the field experience with each of these products to establish some practical guidelines for the selection of polymers depending on the reservoir and fluid characteristics.
One first result of this review is that the limits of conventional HPAM may not be as low as usually expected. Biopolymers appear very sensitive to biodegradation and their success in the field has been limited. Associative polymers appear better suited to near-wellbore conformance control than to displacement processes and some of the new co and ter-polymers are currently being field tested with some measure of success. It appears that the main challenge lies with high temperature rather than high salinity; some field projects are currently ongoing in high salinity (200 g/L) and hardness.
The paper will help set the current limits for polymer flooding in terms of temperature, salinity and hardness based on laboratory work and field experience. This will prove a useful guide for practicing engineers looking to pilot polymer injection in challenging reservoir conditions.
The upscaling of unstable immiscible flow remains an unsolved challenge for the oil industry. The absence of a reliable upscaling approach hinders effective reservoir simulation and optimization of heavy-oil recoveries by use of waterflood, polymer flood, and other chemical floods, which are inherently unstable processes. The difficulty in scaling up unstable flow lies in estimating the propagation of fingers smaller than the gridblock size. Using classical relative permeabilities obtained from stable flow analysis can lead to incorrect oil recovery and pressure drop in reservoir simulations.
Extensive experimental data in water-wet cores indicate that the heavy-oil recovery by waterfloods and polymer floods has a power-law correlation with a dimensionless number (named “viscous-finger number” in this paper), a combination of viscosity ratio, capillary number, permeability, and the cross-sectional area of the core. On the basis of the features of unstable immiscible floods, an effective-fingering model is developed in this paper. A porous-medium domain is dynamically identified as three effective regions, which are two-phase flow, oil single-phase flow, and bypassed-oil region, respectively. Flow functions are derived according to effective flows in these regions. Model parameters represent viscous-fingering strength and growth rates. The new model is capable of history matching a set of heavy-oil waterflood corefloods under different conditions. Model parameters obtained from the history match also have power-law correlations with the viscous-finger number. This model is applicable to water-wet reservoirs; it has not been tested for mixed-wet and oil-wet systems, low-interfacial-tension (IFT) environments, low permeability, and heavy-oil reservoirs with free gas cap.
In reservoir simulations, having such a correlation enables the estimation of model parameters in any gridblock of the reservoir by knowing the local viscous-finger number. The model was first applied to a heavy-oil field case with channelized permeability by waterfloods. Simulation results with the new model indicated that viscous fingering strengthened the channeling. Also, the new model shows that a lower injection rate leads to a higher oil recovery. In contrast, oil recovery in waterflooding of viscous oils is overpredicted by classical simulation methods that do not incorporate viscous fingering properly. We further showed that coarse grid simulations with the new model were able to obtain saturation and pressure maps consistent with fine-grid simulations. The new model was then used to model a real field case in the Pelican Lake heavy-oil field. It was able to match the field-production data without major adjustment of reservoir/fluid properties from the literature, showing its competence in capturing subgrid viscous-fingering effects. Overall, the new model shows encouraging capability to simulate unstable water and polymer floods in heavy-oil reservoirs, and hence can facilitate the optimization of heavy-oil enhanced-oil-recovery (EOR) projects.
Petrophysical cutoffs of a hydrocarbon reservoir are among the key parameters to determine net pay, net-to-gross ratio (NTG), original hydrocarbon(s) in place (OHIP), and reserves estimation. Although the concept of cutoffs has been continuously used since the 1950s, so far there is no universal agreement on their definition and quantification methods. In the most commonly used procedure, log-derived shale-volume faction (Vsh), porosity (ϕ), and water saturation (Sw) are tied back to experimentally measured rock permeability (k) values through a porosity/permeability crossplot. Then, limiting values of the three log-derived parameters are determined by use of fixed-permeability-cutoff values of 1 and 0.1 md for oil and gas reservoirs, respectively. Although these values, which are usually referred to as rule-of-thumb cutoffs, seem to be appropriate in some reservoirs, they can be misleading in most cases (e.g., tight gas and heavy oil). Furthermore, these fixed values have no mathematical basis because they were founded mainly on the basis of the experience in a number of typical reservoirs. Therefore, application of the rule-of-thumb cutoffs may cause significant errors in evaluation of petroleum reservoirs.
This study focuses on technical and economic factors that have to be considered for delineating net pay. Mobility cutoff in this paper is founded on the flow equation (Darcy’s law) and combined with economic-profitability condition to quantify the cutoff individually in gas and oil reservoirs. Thereafter, a novel structured procedure is provided to integrate all core, petrophysical, and fluid data with the calculated mobility cutoff, thereby introducing a single permeability cutoff for the reservoir. One of the advantages of the new procedure over the traditional methodologies is that once a cutoff is determined for permeability, it does not require subsequent tying back to ϕ, Vsh, and Sw to quantify the extra discrete cutoffs. In addition, the technique benefits from the use of permeability distribution within the reservoir in cutoff quantification. The procedure is simple, straightforward, general, and practically rationalized. Despite the previous works, it is noteworthy to mention that the newly developed approach is applicable to all types of hydrocarbon reservoirs, including typical reservoirs, tight oil and gas reservoirs, heavy-oil reservoirs, laminated- thin-bed reservoirs, and discrete stacked reservoirs, with wide ranges of rock and fluid properties. An example calculation is presented for application of the methodology in an Iranian carbonate reservoir. The example clearly illustrates how all available data from a reservoir should be integrated for appropriate determination of the permeability cutoff.
Nigeria has vast amount of gas and gas-condensate resources that have not been developed because of country’s traditional focus on oil reservoirs in the past. However, country is now embarking on a systematic development of gas resources. Objective of this study is to discuss issues being faced by all parties to evaluate gas resources and practical solutions to move forward with gas development on a large scale.
This paper discusses commercial (including team dynamics), technical, data analysis, and organizational capability issues relevant to development planning for gas fields. Practical solutions such as open and full communication among all stakeholders, due diligence to locate and analyze technical data, and proper bench-marking and testing of relevant recovery mechanisms in commercial software packages are proposed that would lead to proper evaluation of gas resources. It is emphasized that work alignment to resolve uncertainties and reach appropriate decisions is absolutely critical for project success. While practical solutions presented in this paper are especially geared toward gas field development, many of these thoughts and concepts are applicable for technical analysis of all petroleum engineering projects.
Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE EOR Conference at Oil and Gas West Asia held in Muscat, Oman, 31 March-2 April 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohi bited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Chemical EOR methods such as polymer flooding and ASP (Alkaline-Surfactant-Polymer) are generally not considered suitable for oil viscosities over one or two hundred cp (polymer) or even less (SP/ASP). However this perception is changing, in particular due to field results obtained from a number of chemical EOR pilots or full field floods implemented in Canada in higher viscosity oil in the past few years. Canada is a country well-known for its heavy oil production; recovery processes such as Cold Heavy Oil Production with Sand (CHOPS) and Steam Assisted Gravity Drainage (SAGD) have been invented there. However cold production is limited in terms of the level of recovery it can achieve and thermal techniques also have limitations in particular when reservoirs are thin. Thus Canadian companies have been pursuing chemical EOR to increase recovery in those types of reservoirs. The aim of this paper is to review some of the Canadian projects for which public information is available. Several mostly unpublished projects will be discussed in details, and conclusions will be drawn on the applicability of chemical EOR methods in heavy oil.
There have been many different approaches to quantifying cutoffs, with nosingle method emerging as the definitive basis for delineating net pay. Yeteach of these approaches yields a different reservoir model, so it isimperative that cutoffs be fit for purpose (i.e., they are compatible with thereservoir mechanism and with a systematic methodology for the evaluation ofhydrocarbons in place and the estimation of ultimate hydrocarbon recovery).These different requirements are accommodated by basing the quantification ofcutoffs on reservoir-specific criteria that govern the storage and flow ofhydrocarbons. In so doing, particular attention is paid to the relationshipsbetween the identification of cutoffs and key elements of the contemporarysystemic practice of integrated reservoir studies. The outcome is a structuredapproach to the use of cutoffs in the estimation of ultimate hydrocarbonrecovery. The principal benefits of a properly conditioned set of petrophysicalcutoffs are a more exact characterization of the reservoir with a bettersynergy between the static and dynamic reservoir models, so that an energycompany can more fully realize the asset value.
In a literal sense, cutoffs are simply limiting values. In the context ofintegrated reservoir studies, they become limiting values of formationparameters. Their purpose is to eliminate those rock volumes that do notcontribute significantly to the reservoir evaluation product. Typically, theyhave been specified in terms of the physical character of a reservoir. If usedproperly, cutoffs allow the best possible description and characterization of areservoir as a basis for simulation. Yet, although physical cutoffs have beenused for more than 50 years, there is still no rationalized procedure foridentifying and applying them. The situation is compounded by the diverseapproaches to reservoir evaluation that have been taken over that period, sothat even the role of cutoffs has been unclear. These matters assume an evengreater poignancy in contemporary integrated reservoir studies, which aresystemic rather than parallel or sequential in nature, so that all componentsof the evaluation process are interlinked and, therefore, the execution of anyone of these tasks has ramifications for the others (Fig. 1). A particularaspect of the systemic approach is the provision for iteration as the reservoirknowledge-base advances. For example, simulation may be used in developmentstudies to identify the most appropriate reservoir-depletion mechanism, but,once the development plan has been formulated, the dynamic model is retuned andprogressively updated as development gets under way.
The principal use of cutoffs is to delineate net pay, which can be describedbroadly as the summation of those depth intervals through which hydrocarbonsare (economically) producible. In the context of integrated reservoir studies,net pay has an important role to play both directly and through a net-to-grosspay ratio. Net pay demarcates those intervals around a well that are the focusof the reservoir study. It defines an effective thickness that is pertinent tothe identification of hydrocarbon flow units, that identifies target intervalsfor well completions and stimulation programs, and that is needed to estimatepermeability through the analysis of well-test data. The net-to-gross pay ratiois input directly to volumetric computations of hydrocarbons in place andthence to "static" estimates of ultimate hydrocarbon recovery; it is a keyindicator of hydrocarbon connectivity, and it contributes to the initializingof a reservoir simulator and thence to "dynamic" estimates of ultimatehydrocarbon recovery.
Billions of barrels of oil remain unrecovered in "bottomwater" reservoirs with a highwater-saturation zone in communication with the oil zone. Typically, the water cut in such reservoirs increases rapidly during primary production, leading to low primary oil recovery. If a water zone were not present, many of these reservoirs would be good candidates for waterflooding. Instead, the performance is poor under conventional waterflood and worse if the oil is highly viscous. Several techniques and production strategies have been proposed recently to improve waterflood performance of such reservoirs. These are the subject of this paper.
Problems In Producing Bottomwater Reservoirs
Water coning is the most common problem in producing oil from a bottomwater reservoir. Once the water reaches the perforations, it is produced in preference to the more viscous oil, and the producing WOR becomes prohibitively high.
In heavy-oil formations, a high water cut often causes excessive sand deposits in the wellbore. A specific minimum oil flow rate is required to mobilize sand in most heavy-oil reservoirs. In most cases, with an increase in the water cut, the sand-carrying capacity of the produced fluids drops considerably and the wellbore sands up.
The detrimental effect of the bottomwater zone sometimes is alleviated by shale breaks, which reduce vertical permeability. A number of heavy-oil reservoirs with water legs have not been affected significantly by an underlying high-saturation water zone because of the presence of frequent horizontal shale breaks. Similar horizontal shale breaks probably will increase productivity in light-oil reservoirs with bottomwater as well.
The Bonnie Glenn field of Alberta is a light-oil bottomwater reservoir that has produced successfully under primary production. This light-oil (35 to 40 deg API) reservoir has a water zone, yet the oil production rate has been steady with little water influx from the bottomwater zone. One interesting feature of this reservoir is the presence of a gas cap. Also, the reservoir has a very high vertical permeability, resulting in an efficient gascap drive with maximum pressure gradient from the top of the reservoir. As a result, oil can be produced with relatively small drawdown and minimum influx from the bottomwater zone. However, the reservoir is maturing after producing (with gas reinjection) some 80% of the original oil in place (OOIP). Currently reported WOR values are high.
Microbially produced organic acids in contact with mild steel pipelines can cause an accelerated form of corrosion similar in appearance to a CO2 type of attack. While the two types of attack may appear to be similar in nature their corrosion mitigation methods are different. Chemical corrosion inhibitors which are effective in controlling CO2 attack could be rendered ineffective when treating microbially induced corrosion.
This case study outlines the procedure taken in identifying the internal corrosion mechanisms responsible for the microbially induced corrosion (MIC) failures, selection of the treatment chemicals, monitoring techniques, health and safety aspects of chemical programs and the potential environmental impact of such programs.
Alberta Energy Company Ltd. owns and operates approximately 3100 shallow gas wells and 3200 kms of flowlines, operating at an average pressure of 1000 kPa in the Suffield Field. The field is situated on a Canadian Forces Military Range located in Southeastern Alberta, Canada. The production, gathering and treatment of sweet gas commenced during 1976 from the Milk River, Medicine Hat and Second White Specs formations. These gases contain less than 0.2% CO2, and no H2S. Line failures were first discovered during 1983, and have increased in frequency as the system aged. By 1991 the total cumulative failures reached 96. Extrapolation of a semi-log plot of cumulative failures versus time (Figure 1) indicated up to 1000 failures could occur by 1998 if the corrosion process was allowed to continue unchecked.
Previous third party investigations found that the corrosion failures were attributed to the activity of Sulfate Reducing Bacteria (SRB) or CO2 corrosion attack. The SRB corrosion was justified based upon culturing of deposits and the presence of iron sulphides. CO2 corrosion was justified by the presence of iron carbonate in the corrosion deposit. The presence of the iron carbonate was attributed to an acid attack resulting from CO2 dissolution in the water under the system conditions. Evaluation of the gas and liquid chemistry and recognition of the low system pressure (initially 2800 kPa), however, make CO2 induced corrosion an unlikely cause of these failures attributed to CO2 attack. An initial bioassay identified a chemical which had a high probability of success in controlling microbially induced corrosion (MIC).
This paper summarizes the historical development of a major Canadian gas field on federal lands. Using applied technology and a proactive, consultative approach among the producing company and all parties affected by the development, the project has proceeded successfully and over 3200 wells have been drilled, completed and placed on production. The total original recoverable gas reserves within the 1019 square mile Suffield field are estimated to be 1.8 trillion cubic feet and over half have been produced to date. Numerous technical and operational challenges had to be addressed during the course of developing these gas reserves in an area which is dedicated primarily to military training complete with live-fire artillery and tank exercises. To add to the developmental challenges, the Suffield gas field also contains unique wildlife species and environmentally sensitive areas.
The Suffield gas field is situated entirely within an active military range, CFB Suffield, which consists of 1019 square miles of area owned by the Government of Canada and located in southeastern Alberta, Canada (Figure 1). Because the area is a military range, there is no public access to these lands.
Large-scale military live-training exercises and defense research activities have priority over other land uses such as gas and oil development and cattle grazing.
While the surface rights to Suffield are owned by the Government of Canada and administered by the Base Commander of CFB Suffield, the petroleum and natural gas rights are owned by the provincial Government of Alberta. In 1972, Alberta commissioned a study which, based upon wells drilled along the perimeter of the range, concluded that significant gas reserves were to be found. The study recommended that 77 evaluation wells be drilled at a cost to the province of $2.5 million. The report was very negative when commenting on the possibility of gas resource development coexisting with military operations. it also outlined three possible development options: 1) sale of the mineral rights to industry; 2) equity participation by the Alberta government with industry; or 3) development by a government agency.
In April of 1973, the federal Government approved Alberta's request for access to drill the evaluation wells. The Suffield Evaluation Committee was then formed under the direction of the Alberta government to arrange the drilling of 77 evaluation wells. These wells were widely spaced throughout the range, and all encountered gas in one or more of the Upper Cretaceous Milk River, Medicine Hat and Second White Specks zones.
This paper describes the development of a combined gas gathering system andreservoir simulator. The simulator solves the reservoir and gathering systemequations in sequence on each iteration, with the well equations acting as theboundary condition for each stage.
The surface equations are a fully implicit set, collectively called thesurface model, capable of handling multiple terminals and looped lines.Boundary conditions for the surface model can be either rate or pressure, andcan be specified either at the terminal level or at the battery level. Aninnovative feature of the surface model is the ability to model operatingconditions in addition to the deliverability condition. This is made possibleby modelling controllers, which cause the problem to degenerate into a numberof smaller problems, each of which must be solved separately.
The three dimensional single phase reservoir model is also fully implicit,as is the well model. A significant feature of the well model is the cross-flowcapability in multilayer completions.
The simulator was originally developed for modelling the Suffield gas fieldin full detail. Suffield is the largest gas field in Canada operated by onecompany. The simulator needed to be capable of handling over 4000 wellsproducing from three horizons. Although the simulator was developed for aspecific application, it is completely general, and is applicable to any gasfield.