Ouled Ameur, Zied (Cenovus Energy Inc) | Kudrashou, Viacheslau (Texas A&M Engineering) | Nasr-El-Din, Hisham A. (Texas A&M University) | Forsyth, Jeffrey (nFluids Inc) | Mahoney, John (Mahoney Geochemical Consulting) | Daigle, Barney (AkzoNobel)
The acidizing of sour, heavy-oil, weakly consolidated sandstone formations under steam injection is challenging because of fines migration, sand production, inorganic-scale formation, corrosion issues, and damage caused by asphaltene precipitation associated with these sandstone formations. These and other similar problems cause decline in the productivity of the wells, and there is a recurring need to stimulate them to restore productivity. The complexity of sandstone ormations requires a mixture of acids and several additives, especially at temperatures up to 360°F, to accomplish successful stimulation. Three treatments were tested on a horizontal well in the field: hydrochloric acid (HCl); Chelating Agent B, a high-pH chelant; and Chelating Agent A, or glutamic acid N,N-diacetic acid (GLDA). The first two treatments with 15 wt% HCl and high-pH (pH=10) Chelating Agent B produced results below expectations. The third treatment using GLDA was successful, and the well productivity increased significantly. The field treatment with GLDA included pumping the treatment fluid, which was foamed to create proper rheological characteristics and a better-controlled pumping process. The treatment fluids were displaced into the formation by pumping produced water and were allowed to soak for 6 hours. In this paper, we evaluate the field applications of GLDA using geochemical modeling, production data, and analysis of well-flowback fluids after the field treatments.
Wehunt, C. Dean (Chevron North America Exploration and Production Company) | Lattimer, Stefan K. K. (Chevron Europe, Eurasia, and Middle East Exploration and Production Company) | McDuff, Darren R. (Chevron Energy Technology Company)
In this paper, we provide an update on recent advances for and summarize global experiences with dendritic-acidizing (DA) methods, or acid tunneling. We include both coiled-tubing (CT) deployed methods and non-CT methods, and discuss process limitations, candidate-selection criteria, job-design factors, operational learnings, risks, and surveillance requirements and opportunities. A comprehensive review of published information is provided for three different tunneling methods along with relevant information for several other tunneling methods. This literature information is supplemented by depth, temperature, and pressure records for the three processes, which are discussed in detail. Execution factors such as logistics required, length of time required, and volumes of acid and other fluids used are also compared for the three methods.
Previous papers have focused on only one of the methods, whereas we will discuss acid-job optimization, process risks, and surveillance requirements for multiple acid-tunneling methods in substantially greater depth than have past authors. The three methods detailed in this paper are all viable but may have different niches. Differences in the job counts for the different methods are easily explained by differences in process vintages, execution speeds, and depth limitations. Previous optimization efforts were focused on tunnel creation but not acid-job effectiveness in terms of the wormholes generated adjacent to the tunnels; however, some progress is now being made in that regard. There are differences in the processes regarding pushing or pulling the jetting nozzles into the tunnels, and differences in resulting tunnel trajectories. Prejob caliper data are more critical for one of the processes than for the others, and there are significant differences in ability to measure or control tunnel direction. The tunneling tools have different sizes, but when toolsize alternatives are available, the larger tool sizes offer no clear advantages to the operator. Useful risk-mitigation measures are also discussed, and a comprehensive bibliography is included to facilitate further examination of the technology alternatives by other petroleum-industry professionals.
For more than 50 years, coiled tubing (CT) has been an intervention technology used primarily to maintain or increase production. In the last 10 years, CT telemetry systems have been used for such applications as milling, stimulation, well cleanouts, gas lifting, camera services, logging, and perforating. These systems have resulted in increased certainty, improved safety and efficiency, and reduced time and cost. In this article, a review of a CT telemetry system with 0.125-in. tube wire, including the technology development and field applications, is presented for the first time. Unlike conventional CT for which surface-measured parameters, such as CT weight and length and pumping pressure, are the only parameters available to monitor the operation’s progress, CT telemetry systems provide real-time monitoring of downhole data such as pressure, temperature, depth, and others. The CT telemetry system described in this article consists of the surface hardware and software, a 0.125-in. tube wire inside the CT connecting the surface equipment and the downhole tools and sensors, and a versatile bottomhole assembly (BHA), designed in three sizes (i.e., 2.125-, 2.875-, and 3.5-in.). The 0.125-in. tube wire has the dual purpose of powering the downhole sensors and transferring the real-time downhole data to the surface. The sensors available are a casing-collar locator (CCL), two pressure and temperature transducers (capable of measuring downhole data inside and outside the BHA), and tension, compression, and torque gauges. In addition, cameras with front and lateral views and flow-through capabilities could be used. One of the advantages of this CT telemetry system is its versatility: Switching between applications is as simple as changing parts of the BHA, significantly reducing the operational time and cost, and increasing safety. Another advantage stems from the acquisition of real-time downhole data, enabling the CT field crew to intervene promptly on the basis of dynamic downhole events. A state-of-the-technology review of the 0.125-in. tube-wire CT telemetry system is presented for the first time. The many benefits of the real-time monitoring of the downhole parameters during such CT applications are summarized. These applications include logging, zonal isolation, collapsed-casing identification, scale removal, cleanout and perforation, milling, confirmation of jar activation during fishing jobs, and others. Many of these applications were performed together, and the real-time monitoring of downhole data increased the job efficiency, control, and safety, and reduced the operational costs by simplifying the operational procedures and equipment.
Fiber-optic (FO) -based sensing technologies such as distributed temperature sensing (DTS) or distributed acoustic sensing (DAS) for well surveillance are attractive because they offer a continuous collection of real-time downhole data without the need for well intervention, thus avoiding production deferment. An example is the application of DTS and DAS for gas lift performance monitoring in oil producers by measuring the thermal and acoustic effects from the flow of lift gas through the valves into the production tubing to determine the active, inactive, and possibly leaking valves, and, also, the unloading depth. An anomaly observed in DTS data of a deepwater Gulf of Mexico (GOM) gas lifted oil producer led to a significantly improved interpretation methodology that allows inferring both the lifting depths and the annular-fluid interface(s). These results were confirmed by DAS, by identifying gas flow through a valve in selected acoustic-frequency bands. The new insights have been applied to five wells in the GOM and Southeast Asia.
Thiberville, Caitlyn J. (Louisiana State University) | Wang, Yanfang (Louisiana State University) | Waltrich, Paulo (Louisiana State University) | Williams, Wesley C. (Louisiana State University) | Kam, Seung I. (Louisiana State University)
Early detection of subsea pipeline leaks is a very serious and ongoing issue for the oil and gas industry with limited successful cases reported. For example, aerial surveillance of pipelines can be applied only for relatively shallow and concentrated areas, and an advanced technology such as fiber-optic cable can be considered at the significant expense of time and cost for installation and equipment. The objective of this study is to evaluate a software-based leak-detection technique through complex multiphase flow mechanics. More specifically, this study investigates (i) how leak-detection problems can be formulated from a fluid-mechanics viewpoint and (ii) how reliable such a technique can be under conditions resembling the deepwater Gulf of Mexico (GOM). In examining a wide range of scenarios, this study proves that software-based techniques have a potential for playing a key role in the future.
First, this study defines a base case selected from the literature review of deepwater GOM flowlines in terms of pressure and temperature conditions, fluid properties, reservoir properties, and flowline characteristics that allows a steady-state flow in pipeline to be determined with no leak present. Next, leaks with certain opening sizes (dleak) at different longitudinal locations (xD = x/L) are positioned, and new steady states in the presence of leaks are calculated. By comparing the two steady-state responses (with and without leak), finally, the changes in two leak-detection indicators [i.e., change in upstream pressure (ΔPin) and change in downstream total flow rate (Δqt out)] can be calculated in a wide range of input parameters. This study presents the results in the form of contour plots for pressure and flow responses.
The major finding of this study is that, theoretically, it is possible to estimate both size and longitudinal location of the leak with the two leak-detection indicators in the software-based leak-detection method. The results from various subsea flowline conditions [such as different gas/oil ratios (GORs) and fluid types, water depths, pressures at the receiving facilities, inclination angles, pipe diameters, water cuts, and so on] show that the reliability of this technique is improved when the sink term (i.e., amount of leaking fluid) is more dominant, which, in turn, means that leaks positioned farther upstream, with larger opening size, and occurring at higher pressure inside pipe are relatively easier to detect. In many of the scenarios considered, Δqt out as a leak-detection indicator shows more than a 10% change in the presence of a leak with dleak > 1 in., allowing relatively easier activation of a leak-warning system, which demonstrates the robustness of this technique. Other scenarios in which the indicators are less than a few percent changes, however, may be challenging—in those cases, additional responses from other methods (hardware-based or transient simulation) will be helpful.
Li, Xiaojiang (China University of Petroleum (Beijing), and Sinopec Research Institute of Petroleum Engineering) | Li, Gensheng (China University of Petroleum, Beijing) | Sepehrnoori, Kamy (University of Texas at Austin) | Yu, Wei (Texas A&M University) | Wang, Haizhu (China University of Petroleum, Beijing) | Liu, Qingling (China University of Petroleum, Beijing) | Zhang, Hongyuan (China University of Petroleum, Beijing) | Chen, Zhiming (China University of Petroleum, Beijing)
The push to extend fracturing to arid regions is drawing attention to water-free techniques, such as liquid/supercritical carbon dioxide (CO2) fracturing. It is important to understand CO2 flow behavior and thus to estimate the friction loss accurately in CO2 fracturing, but no focus on CO2 friction loss in large-scale tubulars has been made until now. Because of the difficulty in conducting field-scale experiments, we develop a computational-fluid-dynamics (CFD) model to simulate CO2 flow in circular pipes in this paper. The realizable k-e turbulence model is used to simulate the large-Reynolds-number fully turbulent flow. An accurate equation of state (EOS) and transport models of CO2 are used to account for CO2-properties variations with pressure and temperature. The roughness of the pipe wall also is considered. Our model is verified by comparing the simulation results with the experimental data of liquid CO2 and correlations developed for water-based fluid. It is confirmed that the friction loss of CO2 follows the phenomenological Darcy-Weisbach equation, regardless of the sensitivity of CO2 properties to pressure and temperature. The commonly used correlations also can give good predictions of the Darcy friction factor of CO2 within an acceptable tolerance of 4.5%, where the pressure range is 8 to 80 MPa, the temperature range is 250 to 400 K, the tubular-diameter range is 25.4 to 222.4 mm, and the Reynolds-number range is 105–108. Of all correlations used in this paper, the ones proposed by Colebrook and White (1937), Swamee and Jain (1976), Churchill (1977), and Haaland (1983) are recommended for field use. Finally, we investigate the influence of flowing pressure and temperature on Reynolds number, Darcy friction factor, and friction loss of CO2, and compare the difference between friction loss of water and of CO2 at different pressure, temperature, and flow-rate conditions.
The flooded-core solid/liquid hydrocyclone, also called a desander, is often used in the upstream oil and gas industry to separate particulate solids from produced water. A desander incorporates a solid/liquid cyclone with an accumulation chamber connected to the apex. Solids collect in the accumulator for intermittent removal while the overflow is discharged continuously. With a flooded-core and static-liquid volume in the accumulator, the trajectory of a sand particle from the cyclone inlet to the apex is changed, compared with that in an open underflow hydrocyclone classifier. In this project, the transfer of solids from the cyclone to the accumulator section is studied, with emphasis on the limiting flux. The settling of solids from the cyclone to the accumulator follows a turbulent, hindered-settling relationship that can be approximated by models used for sedimentation hoppers. Measurement of the apex-flux rate shows a maximum choke point, beyond which solids will back up into the cyclone section. The limiting inlet solids concentration to reach this choke point is approximately 2 g/L for small-diameter desanders. An apex-flux balancing system is proposed to overcome this flux-rate limitation.
The two-scale model for simulating carbonate acidizing has gained substantial attention recently. Five studies dealt with matching experimental data studying regular acid. Four studies considered limestone samples, while the fifth examined one dolomite core with face dissolution. The previous work only considered the pore volume (PV) to breakthrough (PVBT) to match experimental results. Researchers assumed linear kinetics for hydrochloric acid (HCl) carbonate reaction and relied on changing Carman-Kozeny exponents to match experimental data.
Unlike previous studies, experiments were performed on 6-in.-long and 1.5-in.-diameter vuggy-dolomite cores at two sets of temperatures (150 and 200°F) and acid concentrations (15 and 20 wt% HCl). Computed tomography (CT) was used to scan the cores when dry, wet, and after acidizing. Porosity distribution calculated from the dry and wet scans was used to build a rectangular model with the cylindrical core inscribed inside. Nonlinear reaction kinetics were applied. The acid-reaction rate and diffusion coefficient were modified on the basis of X-ray-fluorescence (XRF) results and effluent chemical analysis. Wormhole 3D shape and experimental PVBT were used to assess the quality of model results.
The tuned model was used to simulate a hypothetical 18-in. core as well as large-scale radial experiments to assess its prediction capabilities, and finally the model was used to predict the dolomite-acidizing performance under field conditions.
The simulation runs emphasize that the exclusion of the wormhole shape and branching from the matching process results in an unrealistic match. It is important to simulate the cylindrical shape of the core using the actual porosity distribution to capture the wormhole growth, which is increasingly important when the wormhole propagates near the core perimeter. The present study highlights that matching parameters using experimental data yields a trustworthy model that matches both PVBT and wormhole spatial propagation. Accordingly, there is no need for excessively changing the Carman-Kozeny correlation exponents to match the dolomite-acidizing experiments.
The current model accurately matches the wormhole propagation inside the core along with the PVBT. This model can be tuned using a few acidizing experiments and then can be used to generate an acid-efficiency curve with a high degree of confidence, thus avoiding the extra experimental cost.
The current model was able to match two sets of experiments and follow the experimental trend of longer cores and large-scale radial experiments. It was used to predict acid performance under field conditions. The results show that the optimal PVBT under field conditions is always lower than the one predicted under laboratory conditions; the acid depth of penetration has a significant effect on the acid-efficiency curves; and the vertical flow of acid should be considered in acid-job design.
In hydraulic fracturing, large volumes of fluid and sand are injected into the formation to enhance its transport properties. In conventional fracturing, the fluid pressure is increased monotonically to reach failure in a single cycle. The breakdown pressure can be reduced if we increase and decrease the fluid pressure cyclically (cyclic fracturing). This phenomenon has been tested in other engineering fields, but it is not yet possible to predict the breakdown pressure and cycle in petroleum engineering in the context of hydraulic fracturing. In the present study, we propose a workflow that is based on a modified Paris law to predict the breakdown pressure and the number of cycles in cyclic fracturing. The modified Paris law is based on linear-elastic fracture mechanics (LEFM), which treats the solid domain as an isotropic and linear-elastic medium. We use the data available in the literature for dry Tennessee Sandstone. The samples were hydraulically fractured under triaxial stress, two with conventional and two with cyclic methods. The results show that the tuned Paris law can predict the breakdown pressure and cycle with a good accuracy. The tuned model can help us to design an optimal scenario that is fundamentally different from the conventional method for formation stimulation.
A novel centrifugal pump that increases oil-droplet sizes in produced water has been developed. This paper investigates a concept of pumping-pressure optimization, with respect to downstream separation efficiency, for the new pump. The investigation shows that the coalescing centrifugal pump always increased the separation efficiency of a downstream hydrocyclone. Furthermore, it is shown that the pumping pressure can be adjusted to maximize the improvement. Experimental results demonstrate how pumping conditions that minimize the volume fraction of droplets with a diameter smaller than the cut size of the hydrocyclone maximize the separation efficiency. Finally, it is demonstrated how the concept of pumping-pressure optimization can be implemented in a typical produced-water-treatment plant.