Plunger lift is a proven technique for lifting liquids from vertical gas wells flowing below critical velocity. The use of plunger lift in horizontal gas wells was not initially expected to provide any difficulties or challenges. While it has been relatively easy to make plunger lift function in horizontal wells, truly optimizing production has proven to be much more challenging.
One of the challenges of horizontal wells is moving liquids from the horizontal well bore to the tubing above the bumper spring assembly. To facilitate this bumper springs are landed as deep as possible, which creates operating challenges for both bumper springs and plungers. Bumper spring check valve limitations were identified at high deviation angles and re-designed bumper springs have been deployed to address this. Recent testing has shown that the efficiency of some plunger types can be significantly reduced when used in horizontal wells and the explanation for this decrease as well as the test results are provided.
Plunger control software development for the Sierra field's horizontal well application has led to increased production times and volumes. It has resulted in additional operational benefits that reduce down time caused by cold weather and pipeline pigging operations. The software is embedded into the SCADA control system and can utilize well parameters monitored within SCADA to vary the plunger control parameters.
This paper presents case studies showing the impact of plunger control software for horizontal wells. Case studies detailing operational performance benefits and the performance of various types of plungers in high angle applications are also presented. Additional case studies show the impact on plunger performance of well bore trajectory and liquid hold up in the horizontal well bore. Continuous improvements to strategies and operations have been implemented to fully optimize horizontal gas wells.
The successful development and exploitation of unconventional reservoirs has relied on innovative technologies, such as horizontal drilling, multistage completions, modern multistage fracturing, and fracture mapping to pursue economic completions. It is important to highlight that economic production in these ultralow matrix-permeability reservoirs relies on conductivity that must be generated through hydraulic fractures and fracture-network systems. Simulations demonstrate that shale reservoirs with ultralow permeability require an interconnected fracture network of moderate conductivity (branch fractures) with relatively small spacing between fractures to obtain economic production rates and reasonable recovery factors. This paper discusses two recently developed hydraulic fracturing processes to improve economic recovery in unconventional reservoirs.
The first new process is designed for multistage-fracturing treatments with high pumping rates and low proppant concentration. This method uses the efficiencies of tubing-deployed abrasive perforating. Proppant slurries are then pumped down the coiled tubing (CT) and nonabrasive clean fluid is pumped down the annulus, saving the permanent tubulars from erosion. As a result, the rate down the annulus can be much higher. The pumping rate can be instantly manipulated to customize the placement and concentration of proppant being pumped down the CT. In case of premature screenout, a well could be easily reverse-circulated and cleaned for the next stage. Wellbore proppant plugs eliminate the need for overflushing, and the new approach to fracture stimulation, known as branch fracturing, could be achieved by changing proppant concentration in real time.
The second new process uses a combination of mechanically activated sleeve completions and fracturing of individual intervals with a change in the sequence in which the intervals are stimulated. This new method is proposed with the goal of altering the stress in the rock to facilitate branch fracturing and to connect to induced stress-relief fractures in a single, horizontal well.
In slick water fracture stimulations the standard treatment utilizes water with very few chemicals. In the Horn River Basin during the winter months the water from surface sources can be very cold. Besides the obvious problem of freezing, the low temperature of the frac source water causes serious problems with the effectiveness of friction reducers by increasing the inversion time (the time to maximum friction reduction). In low temperature, high rate conditions the maximum friction reduction may not be reached as the fluid may have travelled a considerable distance through surface equipment, and even down the casing, without the friction reducer being fully effective. This condition can increase pumping pressure, horsepower charges and surface equipment failures. It can also affect the ability to get to design rates for the frac resulting in undesirable conditions such as extending the time to get to rate, being unable to start sand scours or pressuring out early on in the frac treatment.
To solve the problem there have been two key solutions employed: either the water can be heated to a temperature where friction reducer inversion time is reduced and therefore is more effective, or more friction reducer is added to the cold frac source water until the friction pressure is manageable. On a multiple frac campaign in the Horn River these two methods were tested against a novel chemical that increased the effectiveness of the friction reducer in cold water. The presentation will include the field test data and a cost analysis of implementing this on a job by job basis. In addition, the foaming and flow back characteristics of this chemical were tested at near in situ conditions to determine the potential for unplanned consequences.
In addition, the technique is being considered for use in a system where the primary fluid is warm (~ 25°C) brackish produced water but the auxiliary fluid supply may be fresh cold water. The objective is to show the cost and benefit of the chemical solution compared to heating or increasing friction reducer loading. Field testing was required to determine if the chemical solution could be applied more cost-effectively then inline heating of the cold frac water supply at full frac rate. Field testing was also conducted to determine if cold frac source water could be efficiently friction reduced with no external heating using only friction reducer, or a combination of a friction reducer and a novel chemical to reduce inversion time.
Geological storage of carbon dioxide (CO2) is one of the proposed strategies for mitigation of global warming. The CO2 injected into saline formations has less density than that of the resident formation brine. The injected mobile supercritical phase migrates upward and spreads under the sealing rock, due to its buoyancy. While CO2 is in the free mobile phase, there is always a risk of leakage through natural and artificial pathways. Once CO2 is dissolved into brine, it cannot migrate upwards other than by diffusion; and, it can then be retained with a minimal risk of leakage. Therefore, solubility trapping could enable more secure storage.
The objective of this study is the proposal of a CO2 injection well string to increase CO2 dissolution in brine and thereby reduce the risk of leakage of the injected CO2. The proposed well string configuration employs a tubing annulus system equipped with gas lift valves: The supercritical CO2 is injected through the annulus, and fresh brine is injected through the tubing. The designed flow rate of the injected CO2 through gas lift valves enhances dissolution of the CO2 into the injected brine.
A simplified single-phase mechanistic model is developed, and analytical solutions of the governing equations are obtained. Using the developed model, the dissolution of CO2 into brine is characterized by governing dimensionless numbers, such as the Peclet and Sherwood numbers. Scaling relations are presented and can be used to investigate the mixing performance under various operating conditions.
Hydrate reservoirs have been categorized as Type I, II, and III; Type I with underlying free-gas, Type II with underlying free-water, and Type III that is sandwiched by impermeable formations. The most common type of hydrate reservoirs are probably Type III reservoirs, where there is no underlying mobile phase beneath the hydrate layer. Depressurization in Type III reservoirs is characterized by difficulty in reducing pressure over a large region because of limited available surface area for decomposition and low permeability in the hydrate. This is unlike to be the case in Type I and II reservoirs, where pressure could be reduced across a large surface area between the hydrate and the underlying free phase.
A 3D numerical model incorporating heat and fluid flow, along with kinetics of decomposition and (re)formation of hydrate and ice, is developed in this paper. Next, the solution behaviour of Type III hydrate reservoirs in response to application of the depressurization technique is studied, with the goal of understanding the interactions between fluid and heat flow and their effects on the decomposition region. This is achieved by exploring for similarity solutions in Type III reservoirs.
The results of this study indicate that the behaviour of Type III reservoirs is sometimes close to that of diffusion problems, suggesting that a similarity solution exists. This has also been shown to be the case in the literature. However, under some other conditions, it is shown that the solution to this problem is also identical to a travelling wave solution, which is another type of similarity solution often observed in diffusive-reactive problems that exhibit frontal behaviour and sharp gradients. Conditions leading to development of these two types of similarity solutions are identified.
The contribution of this work is in identifying the different solution regimes in Type III hydrate reservoirs. This could help to understand and simplify the modeling of governing mechanisms involved in the process of gas production from the most common type of hydrates.
The paper analyzed experimentally the production characteristics of hot-brine stimulation accompanying the hydrate reformation in the presence of methane hydrate. Many attempts have been to recover commercially the methane hydrate such as depressurization, thermal stimulation, and inhibitor injection. Hot-brine injection coupling thermal recovery with inhibitor injection has been investigated as one efficient production scheme but the hydrate reformation during the dissociation is problematic, that influences negatively the recovery rate.
An experimental apparatus divided the steel body into 12 blocks not only to describe one-dimensional dissociation effectively but to control the temperature accurately. The specified amount of methane hydrate were formed artificially in unconsolidated and packed sediments where average particle size, absolute permeability, and porosity were 260 µm, 4.4 D, and 42 %, respectively. The production trends were observed in the temperature range, 283.85 ~ 303.15 K and in the injection rate, 10 cc/min and 15 cc/min, respectively. Methane hydrate reformed in all tests, of which reason can be the recombination of water and dissociated methane at downstream zones. In early time, the production rate was low but it increased significantly in late time. The former was why most gas dissociated in upstream were consumed to reform hydrate in downstream while the latter was to combine both dissociation amount of initial and reformed hydrate. The dissociation front moved fast at the higher temperature and injection rate. The production efficiency of 15 cc/min and 294.55 K was similar to that of 10 cc/min and 303.15 K. The results confirmed the production behavior of methane hydrate under the reformation phenomenon and could provide with the fundamentals to develop the efficient production scheme based on hot-brine stimulation.
Steam assisted gravity drainage (SAGD) is demonstrated as a proven technology to unlock heavy oil and bitumen in Canadian reservoirs. One of the long-term concerns with the SAGD process is high energy intensity and related environmental impacts. Addition of potential alkane solvents to steam in processes such as ES-SAGD can reduce the high use of energy and green-house emissions in SAGD. However, the principal challenge is the high cost of the solvents. As a result, the economic viability of solvent assisted processes highly depends on the original reservoir and fluid properties and the operating strategy used to co-inject the
The main objective of this study is to compare the simulation results of addition of potential solvents to steam in two different types of reservoirs, cold lake and Athabasca. Propane, Butane, Pentane, Hexanes and Heptanes with different proportions from 1%-20% by weight have been co-injected with the steam. The simulations carried out in absence and presence of initial solution gas to find out the effect of solution gas on performance of SAGD and solvent assisted SAGD processes.
Simulation results show that initial solution gas reduces the oil recovery especially in Athabasca reservoir. A varying thickness non-condensable gas layer impedes heat transfer from the condensing steam to bitumen zone. Hydrocarbon additives create a high oil phase mobility zone resulting in production acceleration. Solvents heavier than butane are considered suitable candidates for Athabasca type and butane gave better results in Cold Lake type reservoir under operating conditions of this study. In addition, a detailed study is carried out on the properties of different phases such as phase mobility, saturation and viscosity at the steamsolvent- oil interface to have a better understanding of the effect of presence hydrocarbon additives in the steam chamber.
A new method for evaluation of production decline analysis of a single well in a tight gas formation is presented. The approach is inspired by practical observations from the Cadomin (Lower Cretaceous) and Nikanassin (Upper Jurassic) formations in the Western Canada Sedimentary Basin (WCSB). The Cadomin is encased sometimes in formations of low or ultra-low permeability, which feed the Cadomin, enlarging significantly the ultimate gas recovery (2 to 3 times) of the well and leveling out the gas production rate. The gas feeding can occur through isolated spots due, for example, to the presence of an unconformity.
The proposed method solves the continuity and flow equations for Cadomin-equivalent gas reservoirs and the encasing low and ultra-low permeability formations, which might correspond, for example, to tight or shale gas reservoirs. The new mathematical solution permits integrating the rates at which the well is producing and the rates at which the low or ultra-low permeability source is feeding the Cadomin-equivalent reservoir. Equilibrium is reached when the contribution from the low or ultra-low permeability reservoir is equal to the rate contributed by the Cadomin-equivalent to the wellbore. The proposed method is flexible enough to allow situations in which a higher permeability source might feed a tighter reservoir connected to a wellbore.
The method has application on different types of production declines, for example Arps exponential, hyperbolic and harmonic declines; and more recently developed techniques such as the power law method. The goal of the model, however, is not to replace any of the conventional approaches, which have their place in decline analysis of specific reservoirs, but rather to supplement them on the basis of practical observations that integrate geology of tight gas formations and gas production rates. In the proposed method we get away from Arps' empirical exponent, b, which has been used (that is good) and abused (that is not good) in the past.
It is concluded that the method developed in this study has application in most types of production declines, including linear and bilinear flow. The solutions are illustrated with actual production rates from tight gas formations in the Western Canada Sedimentary Basin.
Evaluating interwell connectivities can provide important information for reservoir management by identifying flow conduits, barriers, and injection imbalances. The multiwell productivity index (MPI)-based method is a recently-developed tool to infer interwell connectivity based on injection/production data. Previously, the MPI method worked well when tested on several synthetic cases under ideal conditions. In this paper, we show the application of the method on a field case, the heavy-oil Senlac field in Saskatchewan.
Nonideal but common conditions, such as the unavailability of injector and producer BHP's and short term and frequent producer shut-ins, may have a large affect on the results of the MPI method. By using the similarities of the MPI method and another connectivity evaluation procedure, the capacitance model (CM), we define a new connectivity parameter that is less sensitive to nonideal conditions. Dramatic changes of the mobility ratio in heavy oil fields still affect the performance of the model but, by applying a dynamic multiwell productivity index, we reduce this problem. Temporary shut-in of the producers within the sampling interval also leads to less accurate estimation of connectivity parameters and production rates. By applying an equivalent skin model and using the average rate formula, we can overcome this problem.
Compared to connectivity parameters defined in previous studies, the one defined here is more robust and less sensitive to the specific circumstances that are common in field cases. The dynamic model suggested in this paper helps us to model cases with variable mobility ratios more accurately. Applying the modifications suggested here improves the fit between predicted and actual production. Using the new connectivity parameters in Senlac, we observed good agreement between the connectivity map and the geological features of the reservoir.
The procedures and modifications described in this paper enable us to use the MPI method more effectively in field cases with common nonideal conditions, including heavy oil waterfloods. Insensitivity of the model to changing well conditions provides a more versatile tool to analyze field data. Furthermore, if we choose to use the CM instead of the MPI, we find that using information from the MPI can benefit the application of the CM. Applying these approaches, we can have a more reliable understanding of the reservoir heterogeneity and quick prediction of reservoir performance to optimize the waterflood.
Connectivity evaluation between well pairs often plays a key role in model assessment and field management (e.g., Larue and Friedmann 2005; Hovadik and Larue 2007). Knowledge of the interwell connectivity and how it varies across a field may identify or confirm the presence of geological features, such as faults and facies changes. Also, connectivity values can be used in models to predict production and assist in reservoir development tasks e.g., placement of infill wells, and management, e.g., adjusting injection rates and identifying problem wells.
Traditionally reserves management has been an exclusive function for Reservoir Engineers; however in mature fields the need to involve Production, Facilities, Geology, Operations Engineers and Financial Analysts is critical. This paper presents a suggested workflow to improve the way reserves are evaluated, supported, booked and documented with a concerted effort of a multidiscipline team. This paper is focused on tight gas reservoirs and the central idea is to reduce the uncertainty that is always present when dealing with reserves.
Most of the discussion is concentrated in understanding and verifying the hyperbolic decline "b?? factor to be used for production decline analysis; we normally understand the mathematical meaning, but very rarely spend the time understanding the physical meaning and the consequences of using the wrong value. Once the "b?? factor is defined, the proper documentation must be filed for each reserve record and the focus becomes the economic analysis of those reserves which is critical for future development especially in a very volatile economy in which prices are fluctuating a lot.