The electrical submersible pump, typically called an ESP, is an efficient and reliable artificial-lift method for lifting moderate to high volumes of fluids from wellbores. These volumes range from a low of 150 B/D to as much as 150,000 B/D (24 to 24,600 m3/d). Variable-speed controllers can extend this range significantly, both on the high and low side. The ESP's main components include: The components are normally tubing hung from the wellhead with the pump on top and the motor attached below. There are special applications in which this configuration is inverted.
In the early days of the oil industry, saline water or brine frequently was produced from a well along with oil, and as the oil-production rate declined, the water-production rate often would increase. This water typically was disposed of by dumping it into nearby streams or rivers. In the 1920s, the practice began of reinjecting the produced water into porous and permeable subsurface formations, including the reservoir interval from which the oil and water originally had come. By the 1930s, reinjection of produced water had become a common oilfield practice. Reinjection of water was first done systematically in the Bradford oil field of Pennsylvania, U.S.A. There, the initial "circle-flood" approach was replaced by a "line flood," in which two rows of producing wells were staggered on both sides of an equally spaced row of water-injection wells. In the 1920s, besides the line flood, a "five-spot" well layout was used (so named because its pattern is like that of the five spots on ...
The Long Beach Unit (LBU) area of the Wilmington oil field (southern California, US) is mainly under the Long Beach harbor and contains more than 3 billion bbl of original oil in place (OOIP). This oil field is a large anticline that is crosscut by several faults with displacements of 50 to 450 ft. It consists of seven zones between 2,500 and 7,000 ft true vertical depth subsea (TVDSS), the upper six of which are turbidite deposits of unconsolidated to poorly consolidated sandstone (1 to 1,000 md and 20 to 30% BV porosity) interbedded with shales. The gross thickness of 3,300 ft contains 900 ft of sandstone. From its discovery in 1936 to the 1950s, most of the onshore portion of this oil field (the non-LBU area of the Wilmington oil field) was produced using the pressure-depletion oil-recovery mechanism.
Waterflooding is the use of water injection to increase the production from oil reservoirs. Use of water to increase oil production is known as "secondary recovery" and typically follows "primary production," which uses the reservoir's natural energy (fluid and rock expansion, solution-gas drive, gravity drainage, and aquifer influx) to produce oil. This is accomplished by "voidage replacement"--injection of water to increase the reservoir pressure to its initial level and maintain it near that pressure. The water displaces oil from the pore spaces, but the efficiency of such displacement depends on many factors (e.g., oil viscosity and rock characteristics). In oil fields such as Wilmington (California, US) and Ekofisk (North Sea), voidage replacement also has been used to mitigate additional surface subsidence.
There are a lot of reports of formation induced damage of wells world-wide. Despite extensive literature on the subject, formation induced damage is not a standardized part of well design. One reason may be that the associated fundamental mechanism is not yet fully understood, which makes it difficult to implement in design rules. As a step towards practical design, this paper aims at improving the understanding of characteristic mechanisms of well formation interaction by analytical solutions to two simple cases. The first case considered is a vertical well in a compacting reservoir and is solved by elasticity theory. An elastic length parameter is derived, which is function of the axial stiffness of well and shear stiffness of formation. The well is then shown to follow the deformation of the compacting reservoir, with exception of a transient zone around the boundary to the overburden. The elastic length determines the size of this transient zone. Through the transient zone, the axial force reduces towards zero in the overburden. A learning is that in many cases it is sufficient to instrument the well casing or liner to measure reservoir compaction. The result also supports the finding that the high number of well damage in the deep overburden is due to another mechanism: shear deformation or slip of a weak plane crossing the well. This second case is also studied analytically yet based on plasticity theory. Input parameters to this model are shear and moment capacity of the well, shear strength of the formation and a load displacement characteristic of the formation. A general finding is that during such slip, the well is normally not able to resist, and it fails by exceeding the moment capacity at a distance from the shear plane.
The final and third case studied is ovalization of the cross section of a horizontal well due to pressure from the formation. This is a phenomenon occurring in salt and weak shale. It is a more complex interaction problem and a numerical simulation by finite element is used to solve it. A workflow is developed for an uncemented part of a horizontal well in a shale formation. Input parameters are in-situ stress, pore pressure and stiffness and strength of well and formation. Since the vertical stress is larger than the horizontal, the shear mobilization is largest to the side of the casing and shear failure starts there, initiating plastic deformation until contact and start of ovalization by reducing the lateral diameter of the well. By reduction of the mud pressure in the outer annulus, the contact area grows. Finally, the structural capacity of an ovalized casing with full formation contact is calculated. The formation is found to have some supporting effect and the resulting capacity is higher than the capacity of an ovalized casing without formation support.
Li, Nianyin (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Yang, Ming (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Zhang, Qian (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Zhou, Hongyu (Natural Gas Research Institute of PetroChina Southwest Oil and Gas Field Company) | Zhai, Changjin (Zhanjiang branch of CNOOC Co. Ltd.) | Feng, Lei (CNOOC EnerTech-Drilling & Production Co.)
Matrix acidizing is an essential strategy to maintain or increase productivity or injectivity of hydro-carbon wells. However, for loose sandstone reservoirs, the rock skeleton structure is easily de-stroyed by acidizing with conventional acid systems, which results in sand production. Also, the precipitation of metal fluorides, fluorosilicates, and so forth that may occur during acidizing will cause secondary damage to reservoirs. Therefore, we propose a new multiple chelating acid system (NMCAS) with low damage and weak dissolution. The system consists of multiple weak acids, organic phosphonic chelators, anionic polycarboxylic chelating dispersants, fluorides, and other auxiliary additives. Its performance was measured through laboratory tests. First, the dissolution retardation effect and dissolution capacity of NMCAS were analyzed by long-term dissolution tests. Then, the changes of particle size and mineral composition of the rock powder before and after dissolution of NMCAS and a regular mud acid system were comparatively analyzed by a sieving analysis method and x-ray diffraction measurement. Third, the chelating abilities of the system on metal ions were analyzed by a titration method. Moreover, the improvement of seepage capacity was analyzed by a core acidification flowing experiment and scanning electron microscopy. Finally, the dissolution mechanism of the system was further analyzed by energy dispersive spectroscopy. Research results indicate that NMCAS has a good retardation effect and a moderate dissolution ability. After dissolution of rock powder with the proposed acid system, the changes in particle size were less than those of the conventional mud acid system. Also, it dissolved merely a small portion of the clay minerals, but increased the dissolution of quartz, feldspar, and other matrices. NMCAS can prevent secondary precipitation of metal ions during the acidizing process because of its strong chelating ability for calcium ions, magnesium ions, and iron ions. The permeability of sample cores was moderately increased, and they formed obvious dissolution channels; however, the rock skele-ton structure was not destroyed after acidizing with NMCAS. This is because the system reduced the dissolution of clay minerals with larger specific surfaces because of the adsorption effect (a relatively lower reduction in the content of the Al element) while enhancing that of such matrices as quartz and feldspar (relatively larger changes in the content of the Si element). NMCAS can dis-solve the cement appropriately while enhancing the dissolution of the matrices, which protects the rock skeleton structure of loose sandstone reservoirs. The proposed acid solution would be of value for removing formation plugging and increasing the production of loose sandstone reservoirs.
Capacitance/resistance modeling (CRM) is an empirical waterflood modeling technique based on the signal correlations between injection rates and gross production rates. CRM can satisfactorily estimate the gross (liquid) production rate. The oil-production-rate forecast is based on fitting the empirical oil fractional-flow model, the Leverett (1941) oil fractional-flow model, or the Koval (1963) model to the historical production data. We observed that the oil-production-rate forecast in this approach is less satisfactory.
We propose a robust approach that combines CRM gross production prediction with a Buckley-Leverett displacement-theory-based waterflood analytical method—the Y-function method—to calculate the oil fraction flow and to improve the oil prediction capability. The analytical method is based on the results of the historical production performance of either an individual producer or a group of producers in a given area. By using this method, a better understanding can be developed about the production performance, such as the breakthrough time of injected water and possible operational issues, such as water channeling. The analytical model compares oil fractional flow and the cumulative gross production on the producers, yet the value of saturation is not required. As a result, the forecast of the oil-production rate becomes more convenient and straightforward.
Sayarpour et al. (2009a) outlined field examples to compare the estimated oil production obtained using the current empirical oil fractional flow-model approach and the analytical Y-function method. The new method provided another effective way to calculate the oil rate in CRM. The results indicated that the new approach improved the accuracy of the oil-rate calculation and proved convenient in field applications. The objective of this study was not to regenerate the gross-rate forecast of CRM, but rather to improve the oil fractional-flow description and oil-production-rate forecast from the gross rate using the Y-function method.
Ouled Ameur, Z. (Cenovus Energy) | Kudrashou, Viacheslau Y. (Texas A&M University) | Nasr-El-Din, Hisham A. (Texas A&M University) | Forsyth, Jeffrey P. J. (Cenovus Energy) | Mahoney, John J. (Mahoney Geochemical Consulting) | Daigle, Barney J. (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.