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.
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.
An experience of electrical-submersible-pump (ESP) -issues troubleshooting to overcome the high-corrosion media of GSA wells is presented. Additionally, actions taken to extend the run life of pumps are explained. GSA is the company in Algeria that adopted the ESP system including all services; therefore, there was no chance to share experience with other entities in the country. Thus, it became necessary to try all available approaches during a period of 10 years to mitigate ESP failures and, eventually, production downtime.
To overcome the high salinity of >320 g/L, several actions were introduced by either of two ways--ESP equipment or well completion. Simple motors and protectors were changed to tandem to prevent water penetration inside the motor. Power cable was changed from galvanized to Monel armor for high resistance to corrosion. For well completion, single or double 1/2-in. water-dilution lines were adopted and were run along tubing and connected to tail pipe, which runs to perforations. Modification in completion metallurgy also took place, when carbon steel was replaced by Super 13Cr. Supplementary actions were taken at the surface; the pressure switch was connected with a variable-speed drive (VSD) to smoothly shut down the ESP for unforeseen surface-controlled subsurface-safety-valve (SCSSV) closures.
The adopted actions yielded considerable positive results. ESP failures that originated from the motor were reduced from four per year during 2012 to only one failure in 2016. However, salt-deposition blocs were almost prevented, and resulted in decrement in bullheading and coiled-tubing interventions by 85%, except for some wells when salt-bloc buildup was occasionally quicker and more important than water-dilution rate. Running a 1/2-in. injection line along with the tail pipe lowered ESP-shutdown frequency. Also, changing the power-cable type gave roughly good results. After running Monel armor, the number of related power-cable failures decreased, contributing to the reduction of whole failures, because related power-cable failure represented 70% of ESP failures in 2015. Considering Super 13Cr instead of carbon-steel tubing gave positive indications, and reduced sharply related tubing-integrity failure. The problem still exists, however, with very low frequency. For surface equipment, all unforeseen SCSSV closures actuated from the control panel are always accompanied by a gradual decrement of frequency and, consequently, smoother ESP shutdown.
Because our organization is the company that uses ESP with a proper sense in Algeria, this paper presents some best practices to be considered for other companies and ESP contractors that are based in the country or abroad that intend to install an ESP system in very high-salinity and corrosive fields and to adopt a lease model for downhole equipment.
Multifractured horizontal wells (MFHWs) have become the most commonly used technology for developing unconventional oil and gas reservoirs. Because unconventional reservoirs are currently the focus of exploration and exploitation around the world, a growing number of researchers and scholars are concentrating on production-performance evaluation of unconventional MFHWs to obtain the stimulated reservoir volume (SRV) or hydraulic-fracture properties, which are usually obtained from expensive reservoir tests or production logs. Rate-transient-analysis (RTA) techniques that use continuous-production and flowing-pressure data have proved to be convenient and applicable approaches to estimate the reservoir parameters and hydraulic-fracture properties. Although many cases or work flows of RTA have been previously studied, most of those works were performed for shale-gas or conventional reservoirs. Few studies on RTA have been conducted for MFHWs completed in tight oil reservoirs, particularly for actual field cases in which the usually scattered production data significantly increase the difficulty in analyzing the production performance.
In this research, the authors focus on using convenient and economical methods (RTA techniques) to obtain the SRV parameters and hydraulic-fracture properties that characterize the fracturing-treatment effectiveness of an actual MFHW in a tight oil reservoir, which many engineers and technical personnel expect to achieve. A comprehensive work flow [including production-data filtering, flow-regime diagnosis, straight-line analysis, type-curve matching (TCM), analytical-model analysis (AMA), numerical-model analysis (NMA), and uncertainty and nonuniqueness analysis] has been developed to perform a production-performance analysis of an MFHW completed in a tight oil reservoir. In particular, two approaches for calculating the permeability of SRV (kSRV) and effective half-length of hydraulic fracture (Xf) have been introduced. Moreover, the dual permeability parameters, the storativity ratio, and the interporosity coefficient (ω and λ, respectively), have been derived to enter into the AMA model to improve the accuracy of history matching. With the combination of AMA and NMA, the estimated ultimate recovery (EUR) of an actual MFHW completed in a tight oil reservoir can be predicted. Considering the uncertainty and nonuniqueness of the original reservoir parameters or nature of the adopted methods, a probabilistic analysis using Monte Carlo simulation has been performed to address the uncertainty of the analysis results. In addition, a simplified application of the developed method has been introduced. To demonstrate the feasibility and practicability of the developed work flow, two field cases from an actual tight oil reservoir have been analyzed. The consistent analysis results for field cases validate the developed work flow and proposed methods.
Slickwater hydraulic fracturing is an important technology that has enabled the oil and gas industry to economically develop enormous unconventional resources. Despite its great success, this technology faces challenges, especially with proppant transport in complex fractures. Very limited work exists in the literature regarding slickwater proppant flow in subsidiary fractures or predictive correlations to estimate settled proppant-dune heights.
This paper provides a scalable correlation to predict dune height across a wide range of flow rates and proppant concentrations in the primary fracture. A unique feature of this correlation is its inclusion of the friction effect; roughness was introduced to the fracture-slot walls. A 30/70-mesh brown sand was used to conduct the slot-flow experiments and build the correlation. This paper also spotlights the proppant-transport mechanism during proppant-dune development in the primary fracture. Understanding this mechanism reveals key information regarding the horizontal and vertical settled-proppant-size distribution. In addition, experimental results are presented to answer the debatable question of whether slickwater can transport proppant into tertiary fractures. In fact, the data show that proppant in slickwater is not only capable of “turning the corner” but also developing high dune levels exceeding 97% of the tertiary fracture-slot heights.
Fracture height is a critical input parameter for 2D hydraulic-fracturing-design models, and also an important output result of 3D models. Although many factors may influence fracture-height evolution in multilayer formations, the consensus is that the so-called “equilibrium height belonging to a certain treating pressure” provides an upper limit. However, because of the complexity of the algebra involved, published height models are overly simplified and do not provide reliable results.
We revisited the equilibrium-height problem, started from the definition of the fracture stress-intensity factor (SIF), considered variation of layered formation properties and effects of hydrostatic pressure, and developed a multilayer fracture-equilibrium-height (MFEH) model by use of the programming software Mathematica (2017). The detailed derivation of SIF and work flow of MFEH model are provided.
The model is compared with existing models and software, under the same ideal geology condition. Generally, MShale (2013) calculated smaller height, and FracPro (2015) larger height, than the MFEH model. Most of the difference is attributable to the different interpretation of the “net pressure,” and the solving of the nonlinear equations of SIF as well. In the normally stressed case, they are both acceptable, although MShale is more reliable. The discrepancy is much larger when there is abnormally high or low stress in the adjacent layers of the perforated interval. The effects of formation rock and fluid properties on the fracture-height growth were investigated. Tip jump is caused by low in-situ stress, whereas tip stability is imposed by large fracture toughness and/or large in-situ stress. If the fluid density is ignored, the result regarding which tip will grow into infinity could be totally different. Second and even third and fourth solutions for a three-layer problem were found by Excel experiments and this model, and proved unrealistic; however, they can be avoided in our MFEH model. The full-height map with very-large top- and bottom-formation thicknesses shows the ultimate trend of height-growth map (i.e., when the fracture tip will grow to infinity) and suggests the maximum pressure to be used. To assess the potential effects of reservoir-parameter uncertainties on the height map, two three-layer pseudoproblems were constructed by use of a multilayer formation to create an outer- and inner-height envelope.
The improved MFEH model fully characterizes height evolution amid various formation and fluid properties (fracture toughness, in-situ stress, thickness, and fluid density), and for the first time, rigorously and rapidly solves the equilibrium height. The equilibrium height can be used to provide input data for the 2D model, improve the 3D-model governing equations, determine the net pressure needed to achieve a certain height growth, and suggest the maximum net pressure ensuring no fracture propagation into aquifers. This model may be incorporated into current hydraulic-fracture-propagation simulators to yield more-accurate and -cost-effective hydraulic-fracturing designs.
O'Reilly, Daniel I. (Chevron Australia and University of Adelaide) | Hopcroft, Brad S. (Chevron Australia) | Nelligan, Kate A. (Chevron Australia) | Ng, Guan K. (Chevron Australia) | Goff, Bree H. (Chevron Australia) | Haghighi, Manouchehr (University of Adelaide)
Barrow Island (BWI), 56 km from the coast of Western Australia (WA), is home to several mature reservoirs that have produced oil since 1965. The main reservoir is the Windalia Sandstone, and it has been waterflooded since 1967, whereas all the other reservoirs are under primary depletion. Because of the maturity of the asset, it is economically critical to continue to maximize oil-production rates from the 430 online, artificially lifted wells. It is not an easy task to rank well-stimulation opportunities and streamline their execution. To this end, the BWI Subsurface Team applied the Lean Sigma processes to identify opportunities, increase efficiency, and reduce waste relating to well stimulation and well-performance improvement.
The Lean Sigma methodology is a combination of Lean Production and Six Sigma, which are methods used to minimize waste and reduce variability, respectively. The methods are used globally in many industries, especially those involved in manufacturing. In this asset, we applied the processes specifically to well-performance improvement through stimulation and other means. The team broadly focused on categorizing opportunities in both production and injection wells and ranking them—specifically, descaling wells, matrix acidizing, sucker-rod optimization, reperforating, and proactive workovers. The process for performing each type of job was mapped, and bottlenecks in each process were isolated.
Upon entering the “control” phase, several opportunities had been identified and put in place. Substantial improvements were made to the procurement, logistics, and storage of hydrochloric acid (HCl) and associated additives, enabling quicker execution of stimulation work. A new program was also developed to stimulate wells that had recently failed and were already awaiting workover (AWO), which reduced costs. A database containing the stimulation opportunities available at each individual well assisted with this process. The project resulted in the stimulation of several wells in the asset, with sizable oil-rate increases in each.
This case study will extend the information available within the oil-industry literature regarding the application of Lean Sigma to producing assets. It will assist other operators when evaluating well-stimulation opportunities in their fields. Technical information will be shared regarding feasibility studies (laboratory-compatibility work and well-transient-testing results) for acid stimulation and steps that can be taken to streamline the execution of such work. Some insights will also be shared regarding the most-efficient manner to plan rig work regarding stimulation workovers.
Wellbore visualizations are often depicted by use of 2D perspective views. This approach is limited and potentially misleading. Of particular interest to rod-pumping and progressing-cavity pumps is the amount of side loading placed on the rod string throughout the wellbore. By illustrating the trajectory of a wellbore in 2D, some nuanced geometries can be easily lost. For example, a “corkscrew” wellbore, or any other complex wellbore geometry, can be very difficult to depict through simple perspective views. A corkscrew is best visualized at a specific camera angle where the shape is apparent. This best viewing angle is generally not at the simple 90° angle where typical 2D perspective views are generated.
Distributed wellbore-visualization tools can be applied to both the design and analysis of pump installations. Interactive and shared views help to identify points in the well where problems may occur, or have occurred. Strategic placement of downhole equipment such as pump depth relative to perforations and historical fluid levels can be performed in a more intuitive way, taking into account a more accurate understanding of the geometry in a given well.
The use of standards-based modern Web technologies enables the rapid deployment of such a tool to both desktop and mobile devices. The 3D graphics acceleration was previously only available in the Web browser through plugins and other third-party software installations. The 3D graphics can now be rendered natively in most modern Web browsers without the need for any additional software installation. Examples of such native visualizations can be found in Fig. 1.