In this study, conceptual numerical simulation models, with geomechanical properties incorporated, were employed to assess whether polymer flooding or a surfactant EOR process could be viable; with minimal damage to permafrost. These simulations considered the geological subdivisions of permafrost distribution in the subsurface which included: an active layer (seasonally frozen ground); taliks (unfrozen ground between the base of the active layer and permafrost layer and within the permafrost layer); and the unfrozen layer below the permafrost zone. In addition, a major oil zone was included in the model underlying the permafrost section. Significant oil recovery values were predicted, both for injection of polymer solutions and surfactant-polymer solutions and with both horizontal and vertical wells. Surprisingly, addition of surfactant provides lower oil recovery than for polymer flooding alone (under same injection slug size, when all subdivisions were considered in the model). This result appeared to occur because the thermodynamics build into models allows the surfactant formulation to freeze easier than the polymer solution without surfactant. This freezing depletes the surfactant bank, and therefore, lowers oil recovery. On the other hand, this freezing actually promotes growth of the permafrost, whereas, injection of polymer alone causes a mild thawing of the permafrost. One might question whether the thermodynamics built into the simulator are correct, but this result does emphasis that in addition to temperature, the chemistry of the injected formulation may be important in determining the fate of the permafrost. At a certain well distance to permafrost (1,640 ft), horizontal injection wells cause greater thawing of permafrost than vertical wells, when wellbores are close to the taliks. Higher concentration and viscosity of polymer slugs have small potential for thawing permafrost, largely because of the injectivity reduction during polymer flooding (thus allowing slower heat dissipation). Examination of polymer injection as a function of pressure, temperature, and mean stress, suggests that subsidence of permafrost could be negligible. The effects on permafrost subsidence increases modestly as the polymer slug size increases, and decreases modestly as the surfactant-polymer slug size increases. As huge heavy oil reserves exist in Canada and Alaska's North Slope regions, continued resource development in these regions is likely. Therefore, a thorough understanding is required in considering the long-term impact on permafrost stability with the use of modern EOR processes implemented in this unique environment.
The dynamics of a process in which a solvent in the form of a vapor or gas is introduced in a heavy-oil reservoir is considered. The process is called the solvent vapor-extraction process (VAPEX). When the vapor dissolves in the oil, it reduces its viscosity, allowing oil to flow under gravity and be collected at the bottom producer well. The conservation-of-species equation is analyzed to obtain a more-appropriate equation that differentiates between the velocity within the oil and the velocity at the interface, which can be solved to obtain a concentration profile of the solvent in oil. We diverge from an earlier model in which the concentration profile is assumed. However, the final result provides the rate at which oil is collected, which agrees with the previous model in that it is proportional to the square root of h, where h is the pay-zone height; in contrast, some of the later data show a dependence on h. Improved velocity profiles can capture this dependence. A dramatic increase in output is seen if the oil viscosity decreases in the presence of the solvent, although the penetration of the solvent into the oil is reduced because under such conditions the diffusivity decreases with decreased solvent. One other important feature we observe is that when the viscosity-reducing effect is very large, the recovered fluid is mainly solvent. Apparently, some optimum might exist in the solubility, where the ratio of oil recovered to solvent lost is the largest. Finally, the present approach also allows us to show how the oil/vapor interface evolves with time.
A key to recovery improvement is application of improved oil recovery/enhanced oil recovery (IOR/EOR) methods. However, even after detailed studies, moving to the next stage including field pilots is not always easy in the mature and remote Alaskan North Slope. The paper also covers BP's Alaskan viscous oil technology strategy, extraction technologies selection, simulation and analytical studies, laboratory studies, and field trials for various shortlisted methods. A comprehensive study strategy conducted for progressing chemical EOR processes is discussed. The paper also addresses the challenges of obtaining new core and fluid samples for laboratory studies and logistical and economic considerations for field trials due to location and weather conditions in this part of the world.
As a result of improved drilling and completion techniques, an increasing number of wells worldwide utilize multilateral systems to minimize the number of surface penetrations required to maximize reservoir contact. However, these systems increase the complexity, which in turn introduces new failure modes and challenges related to inspection of erroneous completions. The scanning range and measurement capabilities utilizing ultrasound imaging techniques provide a new solution for well diagnosis of multi-lateral completions.
Several attempts to enter the upper lateral of a multi-lateral well operated by a major oil company in Alaska, USA had been unsuccessful. Different technologies were attempted to diagnose the problem but no conclusive results were obtained. In May 2017, an ultrasonic imaging technique based on medical ultrasound imaging was used to inspect the Lateral Entry Modules (LEMs). This paper presents the data collected by an ultrasound downhole scanner demonstrating a novel method for diagnosing multi-lateral wells.
The ultrasound downhole scanner utilizes established technology applied in medical ultrasound imaging (e.g.
The possibly defective LEM was investigated by the scanner. A reference scan of a fully functional LEM in the same well was also made and the results from the two compared. The ultrasound data, visualized both as 2D grey-scale images and 3D-rendered images, clearly show that the upper LEM assembly was not properly aligned with the window of the lateral. Thus, explaining the past unsuccessful attempts to enter the completion. Measurements were made directly on the ultrasound images to document the findings. The results from the survey helped the customer to understand the situation of their well and gave information which was valuable for the decision making process.
McCaffrey, Mark A. (Weatherford Laboratories) | Al-Khamiss, Awatif (Kuwait Oil Company) | Jensen, Marc D. (ConocoPhillips Alaska) | Baskin, David K. (Weatherford Laboratories) | Laughrey, Christopher D. (Weatherford Laboratories) | Rodgers, Wade M. (Occidental Petroleum)
AbstractUsing examples from the Permian Basin of Texas, the North Slope of Alaska, and the Bergan Field of Kuwait, this paper describes how oil geochemical fingerprinting can be applied to diagnose quickly and easily three production problems that may affect highly deviated wells.High-Resolution Gas Chromatography can be used to quantify ~1,000 different compounds in an oil, and the relative abundances of those compounds form a geochemical fingerprint. Geochemical differences between fluids in adjacent reservoirs can serve as natural tracers for fluid origin, allowing changes in production in highly deviated wells to be understood.Application 1: In wells that are fracture stimulated, oil fingerprinting can be used to assess whether induced fractures have propagated out of the target interval and into overlying or underlying formations. Oil fingerprinting can be used to quantify what percentage of the produced oil and gas is coming from each interval and how the effective stimulated rock volume changes through time. This concept is illustrated here with a Permian Basin example.Application 2: In wells with multiple laterals in the same well (such as those in certain North Slope, Alaska fields), sand can settle out of the production stream and form sand bridges that obstruct production from one or more of the laterals. In addition, sand co-produced with oil from shallower laterals can settle at the bottom of the vertical section during regular production and obstruct the entry to a deeper lateral. Geochemical fingerprinting can be used to determine quantitatively the contribution of each of several zones to a commingled oil stream. This technique allows the operator to identify sanded-out intervals for fill cleanout (FCO).Application 3: If two reservoirs are both oil bearing, but are of very different permeability, horizontal wells with an intended landing target in the tighter reservoir may be adversely affected if the well path contacts the more permeable reservoir. The Mauddud reservoir in Kuwait provides examples of this phenomenon. The Mauddud carbonate occurs between two massive clastic reservoirs, the Wara and the Burgan. Average Mauddud porosity is 18% with low permeability (1-10 mD), characteristics which make this reservoir a candidate for horizontal drilling. However, some lateral wells in this carbonate may encounter the adjacent, more permeable reservoirs over a short portion of the well path. In such cases, production from the adjacent reservoir may account for virtually all of the well's production, even though the well was intended to be completed solely in the tighter reservoir. Oil fingerprinting can be used to identify wells affected by this problem.A common theme unifies these three applications: Geochemical differences between in-situ fluids in adjacent reservoirs can serve as natural tracers for fluid movement. However, these techniques have been under-applied as tools for optimization of production from highly deviated wells. This paper illustrates the application of this technology to that well type in a variety of play types.
Temizel, Cenk (Aera Energy) | Balaji, Karthik (University of Southern California) | Suhag, Anuj (University of Southern California) | Ranjith, Rahul (University of Southern California) | Peksaglam, Zumra (University of Southern California) | Wijaya, Zein (HESS) | Inceisci, Turgay (Turkish Petroleum) | Abdelfatah, Elsayed Raafat (University of Oklahoma)
Certain heavy oils that foam under severe depressurization give rise to increased recovery factor and an increased rate of production under solution gas drive. Alongwith stabilizing foam, at lower volume ratios, these oils have the ability of stabilizing dispersion of gas bubbles. Chemistry of oil and its viscosity are the reasons for this. In comparison to conventional oils, response of foamy oils to drawdown of pressure is more favorable; primary recovery factor, rate of production, volume ratio of oil to gas that is recovered and the length of time that a given pressure gradient or rate of production can be maintained, all increase substantially. It is a complex phenomenon with intrinsic properties, thus it requires a robust understanding of each factor in this recovery process. In this study, the significance of factors that influence foamy oil recovery in horizontal wells is investigated and outlined.
A robust commercial optimization and uncertainty software is coupled with a full-physics commercial simulator that models the phenomenon with bubbly oil approach in order to investigate the significance of major parameters, on performance of horizontal wells in a foamy oil reservoir in the North Sea. Fluid properties of Maini et al. are employed. Foamy oil is modeled as small bubbles in oil along with small mobile droplets of gas in oil, larger trapped droplets of gas phase and flowing discontinuous gas foam where bubbles can affect viscosity and compressibility along with foam mobility reduction in relative permeability effects, which are region dependent is incorporated.
Sensitivity and optimization has been done on major reservoir parameters, such as, fluid and rock properties and well operational parameters. Tornado diagrams have been used to portray the significance of each parameter. It is observed that a robust approach on handling of uncertainties in reservoir are as important as management of well operational parameters in the scope of reservoir management.
Reasons for the favorable response of foamy oils in solution gas drive are not well understood and tentative explanations that have been put forward are controversial, where utilization of horizontal wells adds another degree of complexity. This study provides an in depth optimization and uncertainty analysis to outline the significance of each major parameter involved in production performance and ultimately the recovery efficiency in foamy oil reservoirs produced with horizontal wells.
Geological sequestration of carbon dioxide through enhanced oil recovery operation has been recognized as one of the more viable means of reducing emissions of anthropogenic CO2 into the atmosphere. The objective of this paper is to find the best EOR scenario for a compositional grading Iranian oil reservoir to be fed by a giant power plant which produces huge amount of CO2 emission, through simulation study. For this purpose a three-dimensional simplified yet realistic model of the reservoir considering compositional grading was built based on long term production data. Various simulation cases to combine different injection schemes and examining the effect of injection rate were conducted to propose an injection-production strategy that can optimize the oil recovery along with CO2 storage. This study is the first attempt to investigate technical and economic aspects of simultaneous CO2-EOR and sequestration for the nominated reservoir. Besides, this approach could be used for any gas cycling and natural gas storage process into this reservoir.
The results presented in the study clearly demonstrated that continuous CO2 injection scheme through one injection and one production well, is the best scenario for simultaneous EOR and sequestration/gas storage which lead to higher CO2 storage and oil recovery efficiency. Through continuous CO2 injection, this reservoir has potential for large scale CO2-EOR and storage projects (injection of more than 240 thousand metric tons of CO2 per year with only one injection well without any field development plan). Finally an economic study is performed to confirm the best scenario.
Compositional simulation of solvent injection requires reliable characterization of reservoir fluids by use of an equation of state (EOS). Under the uncertainty associated with nonidentifiable components, reservoir fluids are conventionally characterized in the absence of universal methodology. This is true even for relatively simple fluids involving only the gaseous (V) and oleic (L1) phases. No systematic method has been presented for characterization of more-complex fluids, exhibiting three hydrocarbon phases: the V, L1, and solvent-rich-liquid (L2) phases.
This paper presents a new algorithm for systematic characterization of multiphase behavior for solvent-injection simulation. The reliability of the method comes mainly from the binary-interaction parameters (BIPs) newly developed for the Peng-Robinson (PR) (Peng and Robinson 1976, 1978) EOS to represent three-phase behavior, including upper critical endpoints, for n-alkane and carbon dioxide (CO2)/n-alkane binaries. The regression part in fluid characterization broadly follows the concept of perturbation from n-alkanes, which was successfully applied for simpler two-phase fluids in our prior research. The algorithm, in its simplest form, uses only the saturation pressure and liquid density at a given composition and reservoir temperature.
Case studies are presented to demonstrate the reliability of the algorithm for 90 reservoir fluids and their mixtures with solvents. Predictions are compared with experimental data for up to three phases. Results show that the simple algorithm developed in this research enables the PR-EOS to predict multiphase behavior in spite of the limited data used in the regression. Without the use of the BIPs developed in this research, the PR-EOS may fail to predict three phases, or may provide erroneous three-phase predictions.
Livingston, E. (ConocoPhillips Alaska, Inc.) | Lee, D. (ConocoPhillips Alaska, Inc.) | Werner, M. (ConocoPhillips Alaska, Inc.) | Tejo, B. (ConocoPhillips Alaska, Inc.) | Wibisono, K. (ConocoPhillips Alaska, Inc.) | Redman, S. (ConocoPhillips Alaska, Inc.) | Callis, D. (Baker Hughes) | Bostick, C. (Baker Hughes)
This paper documents the success story of the first quad-lateral completion for an Alaskan operator using stacked, rotatable, level 3 junction systems. This well is also the first in the world where the junction system is stacked more than twice in a single well.
This quad-lateral completion design is the product of targeting multiple formation layers from a single wellbore by use of open-hole horizontals with slotted liners. The rotatable, multi-lateral junction system has evolved since the first successful installation on Alaska's North Slope in 2007; it accommodates the increased number of laterals necessary for continued economic exploitation of the West Sak heavy oil reservoir. Diligent communication and preparation were required by the operator and the service provider to successfully execute the installation of this complex completion design. Other keys to success were extensive equipment QA/QC performed prior to mobilization to the rig site and appropriate personnel from the operator and the service provider on location during installation to assist rig personnel.
The quad-lateral completion with stacked junction systems was installed nearly flawlessly from both a time and cost perspective. This successful installation paves the way for the operator's future heavy oil development plans, which include penta-lateral completions using the same stacked junction systems.
This quad-lateral completion design with stacked, rotatable, junction systems is a first globally. This success story will provide insight to other operators faced with similar challenges.
In multilateral wells, several distinct processes including sand production, mechanical failure, and pattern depletion can cause a decrease in overall well performance over time. Within a lateral, sand can fall out from the production stream and form sand bridges that obstruct production from that lateral. In addition, sand co-produced with oil from shallower laterals can settle through the production stream to obstruct the entry to a deeper lateral. However, a decrease in production cannot be assumed to be due to obstructions formed by co-produced sand, since a variety of completely different processes can also reduce production. It is critical to know the cause of decreased production from a well, since which method is used to reverse the decrease in production very much depends on the cause of the decrease.
Geochemical techniques can be used to quantitatively determine the contribution of each of several zones to a commingled oil (or gas) stream. This technique costs less than 1-2% of the cost of production logging. One particularly useful application of this technique is using oil fingerprinting to identify sanded-out intervals for fill cleanout (FCO)
In brief, production allocation is achieved by identifying chemical differences between end-member oils (single-zone samples collected from each of the zones being commingled). Parameters reflecting those compositional differences are then measured in the commingled oil. Those data are then used to mathematically express the composition of the commingled oil in terms of contributions from the respective end-member oils. That result is achieved using a linear algebra manipulation of the concentrations of 150-250 compounds naturally occurring in the end member oils and the commingled oils.
In the current study, we show three examples where this approach was used to identify a sanded out interval in each of three wells. Once the sanded-out interval was identified, an appropriate FCO operation could be conducted. This approach resulted in increased production of 200 BOPD, 500 BOPD, and 400 BOPD in the three respective wells. For those wells, the cost of the geochemical analysis was less than the value of 1 hr of increased oil production.