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.
Part 1 of this series of articles identifies electric arc classification, properties, behavior and methods of thermal energy dissipation among the different types of arcs, and factors for the future progress in electric-arc-rated (AR) PPE quality and reliability. Understanding the properties and behaviors of the different possible types of electric arcs is key to assessing AR PPE.
New knowledge of electric arc classification is helpful not only in current arc incident investigation but also in better understanding past arc incidents. Analysis of specific electric arc incidents is complemented with extensive research on electrical trauma trends based on government data. Part 2 of this series addresses arc hazards, protection fundamentals, and data on electrical fatalities and arc burn trauma.
Fundamentals of Electric Arc Protection
Electric Arc Hazards
Electric arc hazards are not limited to the thermal effect. Large amounts of thermal energy released in the electric arc event is also accompanied by extremely bright light flash, momentary and residual flames, heavy smoke and poisonous fumes, loud sound and molten metal droplets. Pressure waves and flying projectiles are also likely as a result of air pressure build-up with cabinet rupture due to the extreme pressure from arcing inside the enclosed cabinet.
All kinds of AR PPE are first and foremost designed and tested to protect the body, hands, face and head from thermal effects. AR PPE may provide supplementary protection against light flash, molten metal and projectiles, but it provides limited protection against smoke, sound and chronic effects from stress caused by the arc event.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 184648, “Integrating Human Factors Into Well Control,” by Jacob Odgaard, SPE, and Tim Morton, SPE, Maersk Drilling, prepared for the 2017 SPE/IADC Drilling Conference and Exhibition, The Hague, 14–16 March. The paper has not been peer reviewed.
Many of the worst oilfield incidents have been attributable to human factors. Consequently, a corporate well-control manual was refreshed to include human factors in the management of well-control incidents. This required mapping the well-control process, assigning specific roles to personnel, and defining contingencies while acknowledging the effect human factors have on the personnel involved. The intention was not to create a rigid structure but rather to provide a framework to guide the front line in dealing with a well-control event.
The corporate well-control manual was updated to introduce human factors and consolidate a number of improvements. Numerous references were consulted, including other industry well-control documents, trade publications, and academic papers.
“Human factors” refers to technological, organizational, and job factors, as well as human and individual characteristics that affect how people perform a job. It includes the competence and behavior of personnel, the design and functionality of equipment, and organizational structure and support.
Why was it necessary to include human factors in something as fundamental as a well-control manual? Many diverse challenges are faced in well control, often involving multiple complex interfaces in a high-stress environment. Frequently, the problem is not fully understood, either. The challenges of decision making in such a pressured environment have been recognized in other industries, and they share many similar features.
The recognition in the drilling industry to include human-factors mitigation into emergency management and, specifically, well control was one of the outcomes of the Macondo disaster. Recognizing the importance of this, a Human Factors Task Force was established to identify improvements related to human factors and their contribution to such incidents. Training- and competence-assurance guidelines were issued, and objectives were set to provide a step change.
Human Factors in Well Control
Well control is often a stressful, high-risk situation, and it is important to understand the effect of how people perceive and react to a well-control situation.
Mental Traps. Managing a well-control situation is stressful, and a number of mental traps need to be dealt with for a successful outcome. These traps are common in situations similar to well-control incidents, and they increase under time pressure or when people become fatigued because of long periods of stress, both of which are experienced frequently in a well-control incident.
Cognitive Biases. A cognitive bias typically occurs when information is interpreted and an attempt is made to simplify complex information.
A cognitive bias may also be seen as a tendency to confirm some preconception or possibly discredit some information that does not support an entrenched view. Such biases have a major influence on the ability of both the individual and the team to understand what is happening during a well-control operation.
Asphaltene precipitation and deposition are major flow-assurance issues that can reduce or completely stop the production of oil wells. To evaluate the severity of asphaltene problems in an oil reservoir, various laboratory tests should be planned. In this paper, a stepwise experimental approach is proposed to assess the asphaltene issue in oil reservoirs. Taking representative oil samples downhole is the first step to accurate experimental investigations. In case the sample does not represent the reservoir status correctly, all the laboratory data—even with accurate measurement—could be misleading. Then, reservoir-fluid characterization and saturate/aromatic/resin/asphaltene (SARA) analysis should be performed for primary evaluations and asphaltene-stability screening. Asphaltene-onset-pressure (AOP) measurement indicates the point at which asphaltene comes out of the solution. After that, assessment of asphaltene-precipitation potential depending on production scenarios (e.g., depletion or gas injection) at reservoir conditions should be performed. Finally, the effect of deposited asphaltene should be characterized in the presence of porous media in terms of deposition amount and its consequent permeability impairment. Eventually, this approach is used for an Iranian oil reservoir.
This experimental approach, along with modeling and simulation of asphaltene precipitation and deposition, can be used as the best practice for assessing the asphaltene issue in oil reservoirs.
Commercial compositional simulators commonly apply correlations or empirical relations that are based on fitting experimental data to calculate phase relative permeabilities. These relations cannot adequately capture the effects of hysteresis, fluid compositional variations, and rock-wettability alteration. Furthermore, these relations require phases to be labeled, which is not accurate for complex miscible or near-miscible displacements with multiple hydrocarbon phases. Therefore, these relations can be discontinuous for compositional processes, causing inaccuracies and numerical problems in simulation.
This paper develops for the first time an equation-of-state (EOS) to model robustly and continuously the relative permeability as a function of phase saturations and distributions, fluid compositions, rock-surface properties, and rock structure. Phases are not labeled; instead, the phases in each gridblock are ordered on the basis of their compositional similarity. Phase compositions and rock-surface properties are used to calculate wettability and contact angles. The model is tuned to measured two-phase relative permeability curves with very few tuning parameters and then is used to predict relative permeability away from the measured experimental data. The model is applicable to all flow in porous-media processes, but is especially important for low-salinity polymer, surfactant, miscible gas, and water-alternating-gas (WAG) flooding. The results show excellent ability to match measured data, and to predict observed trends in hysteresis and oil-saturation trapping, including those from Land’s model and for a wide range in wettability. The results also show that relative permeabilities are continuous at critical points and yield a physically correct numerical solution when incorporated within a compositional simulator (PennSim 2013). The model has very few tuning parameters, and the parameters are directly related to physical properties of rock and fluid, which can be measured. The new model also offers the potential for incorporating results from computed-tomography (CT) scans and pore-network models to determine some input parameters for the new EOS.
Polymer flooding is a widely used commercial process with a low cost per barrel of produced oil, and hydrolyzed polyacrylamide (HPAM) polymers are the most widely used type of polymer. The objective of this research was to better understand and predict the behavior of HPAM polymers and their effect on residual oil saturation (ROS), to improve the capability of optimizing field design and performance. The corefloods were performed under typical field conditions of low pressure gradients and low capillary numbers. The polymer floods of the viscous oils recovered much more oil than the waterfloods, with up to 24% lower oil saturation after the polymer flood than after the waterflood. The experimental data are in good agreement with the fractional-flow analysis by use of the assumptions that the true ROSs and endpoint relative permeabilities are the same for both water and polymer. This suggests that, for more-viscous oils, the oil saturation at the end of a waterflood (i.e., at greater than 99% water cut) is better described as “remaining” oil saturation rather than the true “residual” oil saturation. This was true for all the corefloods, regardless of the core permeability and without the need for assuming a permeability-reduction factor in the fractional-flow analysis.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 181680, “A Continued Assessment of the Risk of Migration of Hydrocarbons or Fracturing Fluids Into Freshwater Aquifers in the Piceance, Raton, and San Juan Basins of Colorado,” by C.H. Stone, SPE, A.W. Eustes, SPE, and W.W. Fleckenstein, SPE, Colorado School of Mines, prepared for the 2016 SPE Annual Technical Conference and Exhibition, Dubai, 26–28 September. The paper has not been peer reviewed.
Wellbore-construction methods, especially casing-and-cementing practices for the protection of freshwater aquifers, have been reviewed in the Piceance, Raton, and San Juan Basins in Colorado. The assessment confirms that natural-gas migration occurs infrequently but can happen from poorly constructed wellbores. Analysis confirmed no occurrence of hydraulic-fracturing-fluid contamination. The significance of these results is to help quantify the risks associated with natural-gas development as related to the contamination of surface aquifers.
The prevention of contamination of freshwater aquifers has been a prime concern in drilling operations since the inception of drilling. Surface casing has long been the primary barrier to prevent contamination of freshwater aquifers through wellbores. The probability of leakage into aquifers from wellbores during shale development has a wide range of estimates, complicated by the presence of hydrocarbons at shallow depths in many parts of the world. An earlier paper reviewed the process and outcomes of a study for the Wattenberg Field in the Denver-Julesberg Basin. This study continues the examination of the contamination of aquifers in the subsurface during the completion and the production phases of the well and quantifies the risk of contamination of aquifers through failure of the wellbore for three other major basins in Colorado, the Piceance, Raton, and San Juan Basins. This synopsis focuses on the assessment of the Piceance Basin.
Barrier Definition. Common vertical, deviated, and horizontal subsurface wellbore-barrier designs were grouped and ranked on the basis of the risk of multiple barrier failures (Fig. 1). For the sake of clarity, pressure monitoring of the casing annulus [surface annulus pressure (SAP)] was not assumed to be an additional barrier during the production phase even though it is frequent and often required by state regulations.
Well-barrier designs can vary from field to field depending on geology, trajectory, depths, anticipated pressures, expected hydraulic-treatment rates, and estimated production rates. Whether a well is horizontal, vertical, or deviated has no significance with respect to the ultimate protection of freshwater aquifers because the wells are designed to protect the shallow vertical section of each oil and gas well. Multiple barriers must be in place near the depth of the freshwater aquifer to prevent breaching of a single barrier potentially leading to contamination.
This paper highlights the care to be taken by an engineer while specifying and selecting a centrifugal compressor for carbon dioxide (CO2) compression.
With the increase in the levels of CO2 in the atmosphere, there is an increase in the popularity of capturing CO2 emitted from the large source points such as fossil-fuel power plants, steel mills, cement plants, and others before its release to the atmosphere and storing it in geological formations [also used for enhanced oil recovery (EOR) where possible]. The compressors used to transport and store the CO2 at such depths need to compress the gas from atmospheric pressure to the pressures on the order of 200 bar or more.
The critical temperature of CO2 is only 31.1°C, so the CO2 is generally transported and stored in a supercritical state. The thermodynamic properties of supercritical CO2 are considerably different from those of the other real gases that are generally compressed. Further, to achieve this supercritical state, the critical point of CO2 is crossed somewhere in the compression stage. Near critical point, the ideal-gas law will not hold for CO2. Moreover, there is a reduction in the choke margin of the compressor caused by the reduction of the sound speed in CO2, particularly near the thermodynamic critical point. Also, the CO2 compressibility and specific heats are not linear near the critical pressure and temperature. The impurities in the CO2 will affect further the thermodynamic characteristics of the working fluid. Also, the water content in the CO2 makes it extremely corrosive.
Considering all the aspects mentioned previously, specifying the CO2 compressor correctly in terms of the equation of state (EOS) to be used, the interstage pressures and temperatures to be maintained, suggesting the number of impellers per stage to maintain the desired flow coefficient, metallurgy to be selected and scheme of compressor dry gas seals, and others becomes all the more important and is described in the paper.
Africa was first called the “Dark Continent” in the 19th century. The term is originally credited to the famous explorer Henry Stanley from his 1878 book “Through the Dark Continent.” Back then, Africa was a mysterious and dangerous place for European explorers.
Today, when I conclude most of my presentations, I use the NASA satellite photograph of the world at night. In it, Africa is mostly dark, so from an energy standpoint, it’s still a “dark continent.” According to the World Energy Outlook 2017, two-thirds of people in sub-Saharan Africa do not have access to electricity. More than half of the population uses wood and charcoal as its primary energy sources, and that is expected to continue until 2040. Lack of access to energy holds back the promise of Africa and its people.
I have spent a lot of time in Africa in the past 10 years. Not only have I traveled to Angola through my position with Chevron, but I also have vacationed there. Most recently, I have traveled to Angola as SPE President. Africa is, in many ways, the final frontier. There are many exciting new developments in African exploration and production that hold tremendous potential to bring more energy and prosperity to the continent—and shine a light of affordable, abundant energy.
West Africa has dominated the continent’s production for more than 50 years since Shell/BP began production in the Oloibiri field in the Niger Delta in 1958. Similarly, Gulf Oil—now Chevron—began offshore production in the Cabinda province of the Congo River basin in Angola in 1968. Angola had a long history of oil seeps dating to 1700s. The first onshore production was in the Benfica field in 1956, but the Malongo field was the first significant commercial production.
Despite long enjoying control over African production, both Nigeria and Angola are now struggling to find the right split between government and commercial interests for in-vestment to continue. Estimates are that investment in deep-water Angola and Nigeria has been cut by USD 100 billion. Without new investment, production will decline by half of its current level.
Nigeria is restructuring its governance and petroleum industry financing, which—if successful—should bring stability and greater investment back into the Niger Delta. Offshore Angola projects are suspended across all operators, pending fiscal reforms that reduce government share under current production-sharing contracts, which can be as high as 90%.
Matrix acidizing is a stimulation technique aiming at improving formation permeability or bypassing damaged zones. In this process, acid is injected through the well into the wellbore vicinity to dissolve the rock. For either production or injection wells, the formation may contain multiple phases (oil and water) near the wellbore region when acid treatment begins. In this paper, a two-phase two-scale continuum model is developed to simulate wormhole propagation under radial coordinates. The model describes the mechanisms of convection, dispersion, and reaction in two-phase flow during matrix acidizing. We have validated the simulation model with two methods: one is to compare with the previous simulation results; the other is to compare with the analytical solution. We have investigated conditions that will affect the wormhole-propagation process, including rock wettability, oil viscosity, and initial oil saturation. It is found that the water/oil mobility ratio is a key factor that affects acidizing efficiency. In addition, we have proposed a new criterion for acid breakthrough because the pressure response is affected not only by reaction, but also by overall mobility change in the formation. The traditional criterion for the single-phase model is no longer applicable to the current two-phase model. The results show that adverse water/oil mobility ratio leads to a higher efficiency for wormhole breakthrough. In carbonate reservoirs with heterogeneity, water/oil displacement and wormhole propagation contribute to narrower, less-branched channels. For the first time, it is possible to simulate formations with multiple phases during carbonate acidizing. The presented model improves our understanding in the optimization of carbonate acidizing.