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Abstract It is commonly known that geological structure and its resultant natural fractures are the predominant factors governing hydrocarbon production from carbonate reservoirs. Through a detailed petrophysical study on a low permeability carbonate play, the authors have obtained new understandings toward the reservoir properties of low permeability carbonate. First, in absent of major geological structures, reduced relative permeability to hydrocarbon is the primary trapping mechanism. Second, the irreducible water saturation range for low permeability carbonate increases significantly. Third, the enlarged irreducible water saturation range makes the curve of relative permeability to hydrocarbon much steep. Therefore, the relative permeability to hydrocarbon is very sensitive to water saturation, and formation water saturation becomes a critical factor affecting hydrocarbon production. The results of this petrophysical study have been successfully applied to identity the "fairways" among a huge low permeability carbonate deposition. Introduction The Niobrara Formation at the Wattenberg Field in the Denver-Julesburg basin is a low permeability carbonate reservoir (Figure 1). It continuously exists throughout the entire field. The Niobrara is a sequence of interbedded carbonate and marine shale. The gross thickness varies approximately from 250 to 350 feet. The permeability tested to the carbonate part is in the order of micro-Darcy. Largely because of it extremely low permeability and unconfirmed potential, this carbonate play used to be treated as a secondary objective for 10 years (between 1996 and 2006) by most operators at the Wattenberg field. Started a few years ago, operators have renewed their interests toward the Niobrara Formation. Numerous pilot projects have been conducted by either separately completing or re-completing the Niobrara Formation. Before any wells are drilled, the first question operators have to answer is where are the best parts of the Niobrara Formation among such huge field as Wattenberg covering approximately 3600 square kilometers (more than 42 townships). In other words, how to define the boundaries dividing economic area and non-economic ones? Many carbonate reservoir related paradigms have failed to find their usefulness at the Wattenberg field. For example, in typical carbonate formation natural fracture resulted from geological structure is a critical factor governing hydrocarbon production. At the Wattenberg field, many wells tested along two well-defined major faults are not better in performance than others. In order to find the petrophysical factor that controlling hydrocarbon production, the authors carried out a petrophysical study and found the method to delineate the "fairways" where the Niobrara Formation performs better than other part of the field. The correlation between well-log calculated water saturation (Sw) and well performance This petrophysical study is supported by a wealthy well log data resource, which includes digital well logs collected from more than one thousand wells where the Niobrara Formation has been penetrated when deeper formations were originally the primary targets. Using self-developed computer programs as well as commercial ones, we calculated the representative well log parameters of the Niobrara Formation, such as the porosity, SP, formation water saturation, and the cross-over area between the neutron and density curves. In order to search the distribution patterns of these parameters, we mapped these parameters. Their distribution patterns helped us identify the areas where the Niobrara reservoir quality is better than that of other part of the field.
Abstract Chang 3 reservoir in Hua 152 block is located in the Ordos basin, China. The average permeability and porosity is 3.17mD and 14.9%. There exists serious scaling at the oil layer near to bottom hole because of high salinity formation water and incompatible injection water. The scaling process and mechanisms in the layers has been researched by means of a visual real-sand micro-model. The results have shown that:The permeability of the oil layer will reduce by 40% when formation water contacts with injection water twice times at the same place; It is very easy for scaling molecules to crystallize from water phase and scale particles are very small because the pores and throats of the formation rock contain a lot of fine clay and impurity; The scale accumulates in pores and looks like "chicken roost"; The scale inhibitors can reduce scaling, but the higher concentration of scale inhibitors is needed. Scaling in low permeability reservoirs may significantly reduce rock permeability thus affecting the production of oil well. The visual real- sand micro-model is a good method to use in research of scaling mechanisms because of its visualization, using actual rock and ease of construction. Introduction If injection water with formation water is incompatible in reservoirs, scaling deposition will be produced and cause formation damage[1–3], and maybe even make permeability reduce by over 90%. There are several factors that influence the degree of scaling damage, that is:Reservoir properties like permeability, porosity, pore structure, heterogeneity, rock composition, reservoir temperature and etc. Ion composition and concentration of injection water and formation water. The scale distribution, scale composition, scale morphology and scale quantity. Therefore, it is important and essential for realizing scaling process and decreasing scaling trend to study[1–5] scaling mechanism in different reservoirs. Many researchers have done a lot of work about scaling damage mechanisms; the main damage mechanisms are as follows:Scale crystals are formed from heterogeneous-phase nucleation in porous media and grown on the surface of pore and throat. Pore and throat are reduced because of scale crystal growing larger. Scale crystals plug pore and throat because of migration in porous media. Core and sandpack experiments are the main methods of studying scaling mechanisms. But it is difficult to observe the scaling formation and distribution directly by means of these methods. So the results and discussions in this paper relate to the scaling and damage mechanisms of Chang 3 low permeability reservoirs in Hua 152 block by using the real sand micro-model, which is made using reservoir rock cores. Scale distribution can be observed under the microscope directly and the degree of scaling damage can also be obtained using the method. Reservoir characteristics Chang 3 formation is located in the Ordos basin of China and belongs to low permeability lithologic oil reservoirs. The average permeability and porosity is 3.17mD and 14.9% respectively. The formation rock is mostly made of arkose aleurolite. The composition of the formation rock is shown in table 1. The maximum throat diameter, which contributes to rock permeability, is 1.24 to 3.2µm based on intrusive mercury method.
Re-Injection is one of the most important methods to dispose fluid associated with oil and natural gas production. Disposed fluids include produced water, hydraulic fracture flow back fluids, and drilling mud fluids. Several formation damage mechanisms are associated with the injection including damage due to filter cake formed at the formation face, bacteria activity, fluid incompatibility, free gas content, and clay activation.
Fractured injection is typically preferred over matrix injection because a hydraulic fracture will enhance the well injectivity and extend the well life. In a given formation, the fracture dimensions change with different injection flow rates due to the change in injection pressures. Also, for a given flow rate, the skin factor varies with time due to the fracture propagation. In this study, well test and injection history data of a Class II disposal well in south Texas were used to develop an equation that correlates the skin factor to the injection flow rate and injection time. The results show that with time, the skin factor decreases until such a point at which the fracture dimensions are sufficient without further propagation to handle the injected water volume (stationary fracture). A constant skin factor is noted after this point. At higher injection flow rates, the constant skin factor achieved is lower because of the larger fracture dimensions developed at higher injection flow rates.
Hongchun, Huang (China University of Petroleum(Beijing)) | Ning, Sun (DRI of China Natl. Petroleum Corp.) | Jinhai, Yu (DRI of China Natl. Petroleum Corp.) | Jie, Feng (DRI of China Natl. Petroleum Corp.) | Hui, Wang (DRI of China Natl. Petroleum Corp.)
Abstract Air/gas drilling is an acknowledged practical technology for its significant advantages in rate of penetration enhancement, lost circulation prevention and hydrocarbon reservoir protection. Air/gas drilling technology, however, can only be applied to dry formations in nowadays. When formation drilled water produces, air/gas drilling needs to be converted to mist drilling, foam drilling or liquid mud drilling, which can result in dramatic reduction of drilling speed. This problem becomes the bottleneck to further extend gas drilling applications in a larger scale in China. Aiming at solving water influx problems in the field application of gas drilling, a new technical method was proposed through in-house research. The water production zone and water cut of drilled formation are predicted using the seismic, logging data and the seepage mechanics theory. When the drilled formation begins to produce large volume of water, a material (water absorbent) is injected to promptly absorb the downhole produced water and remove it out of the wellbore, so as to maintain the normal gas drilling. Furthmore, as drilling goes into well sections with incompetent or large water-cut formations, the expanded tube is employed to mechanically plugging the complex borehole section, which enables the air/gas drilling to be continuecd. Based on this solution, a water absorbent with high efficiency was screened out. Related operational procedures of absorbent injection and expanded tube plugging were studied. Field pilot test shows that with the technique, the borehole section in air/gas drilling can be extended, making the best use of air/gas drilling to increas penetration rate, which hence plays an important role for promoting the use and the advancement of air/gas drilling technology.