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This article presents a simplified mathematical model based on the energy-work method to estimate the penetration depth in well perforation. The model uses casing and formation properties in the estimation. It uses the initial speed of the bullet and the failure strengths of the materials resisting penetration as model input. An automated computer program was developed to compute the penetration depth in terms of various field parameters. It was found that bullet penetration increases with increasing jetting velocity and decreasing effective bullet surface area, and that the use of explosive-type HMX1 yields higher penetration depth for the same bore size. The results also showed that the productivity ratio becomes much higher for larger borehole diameters and higher explosive speeds. Overall, the study showed that the model can be used to design for optimum penetration depths leading to an optimum productivity ratio.

A mechanism of a commingled Huff 'n Puff cycles of gas cross flow from a highly pressurized lower formation into a depleted upper formation has proven to be effective in reducing gas-well productivity losses due to near-wellbore condensate dropout. Compositional simulation was used to evaluate the performance of gas wells hampered by liquid dropout and to assess ways of producing the gas field. As a result of liquid re-vaporization the study shows that an appropriate scheduling of huff 'n puff shut-in and production cycles lead into a decline of in-situ liquid dropout and an increase in surface liquid recovery.

Pressure–Volume–Temperature (PVT) empirical correlations result from analysis of experimental data collected from laboratory measurements of phase behavior properties of hydrocarbon systems. The correlations are only applicable for the tested hydrocarbons. They could nevertheless be used to predict PVT properties of similar hydrocarbons with pressures and temperatures falling within the measurements’ data range. The developed correlations are mostly, local, some are “region-bound” and a few are global. Regional and global correlations are used with caution. The reason being that hydrocarbon systems from different regions have different composition and paraffinicity, regardless of comparable temperature and pressure ranges. As a result and due to a complex geology resullting from unique depositional environments of most Omani reservoirs, a local correlation to derive PVT properties for Omani crude oils is needed. The correlations could also be used to supplement PVT experiments often time consumin...

Gas-condensate reservoirs exhibit a near-wellbore complex behavior due to the existence of a two-phase system when pressure drops below dew point. In analyzing well-testing data, a single-phase approach is only valid for well condition above dew point, whereas a multi-phase pseudo-pressure approach is widely adopted for a gas reservoir operating below dew-point. This article utilizes the pseudo-pressure approach, for analyzing well-test data in gas-condensate reservoirs producing below the dew-point pressure, to generate Corey exponents for relative permeability in order to determine near-wellbore representative relative permeability that history matches the actual well-testing data.

Capillary pressure and resistivity are important parameters that are mostly used in reservoir and petrophysical characterization. Capillary pressure data remain difficult to obtain and classical experimental methods used are questionable and not very adequate. One major drawback in running capillary pressure experiments is the use of fluids other than formation fluids. Another resides in the difficulty to measure capillary pressure at representative reservoir conditions. One more drawback, to name a few, is the experiments time which remains very prolonged, especially when the formation to be characterized is tight because the fluid drainage can take up months if not more. To overcome the intrinsic difficulties of having representative data, an empirical equation relating resistivity to capillary pressure was developed. In this work, twenty-five core plugs of Omani sandstone have been used in an attempt to come up with a representative correlation.

Pressure–volume–temperature (PVT) properties are critical to reservoir as well as production engineers, in particular. PVT properties could be determined experimentally. But, experiments are time consuming and costly. Moreover, laboratory PVT analysis does not consider the variations of PVT properties with respect to temperature since they are measured at reservoir temperature at the time of sampling. For that matter, the data is not benefitable. But, even if experimental analysis is done, it is difficult to obtain representative results to develop a new field. To tackle the above and other related problems, relying on sound PVT emperical correlations would be the ultimate solution. In this work, the intent is to develop stochastic models for PVT properties pertaining to Omani crude oils since it is believed that such correlations are scarce and not very precise. The empirical equations are developed for saturated Omani crude oils. The correlations are tested and validated. The empirical equation...

Reservoir simulation sensitivity analysis and unit technical cost analyses are used in order to determine the optimum well performance of a horizontal well that is selectively completed in one of the fractured Omani reservoirs. A black-oil model representing one heavily fractured Omani field was used in the analysis with a match box-like reservoir structure. The fractures are taken as thin streaks penetrating the reservoir vertically with high permeability along X, Y and Z- directions. Matrix block permeability values are drastically lower than those characterizing fracture block permeability. Eclipse 100 black-oil simulator was used throughout the study to analyze the effect of fracture frequency and to obtain the optimum completion by investigating different isolation length for fractured horizontal producers, injectors and both producers and injectors. The sensitivity analysis involves building numerous models for 2mD, 10mD and 50mD. That is because the range of permeability in the field is no...

Oman produces around 850,000 bbl/day of crude oil from around 85 fields of which 35% comes from horizontal wells. Horizontal drilling was started in 1986 with three short radius wells drilled in chalky oil reservoirs due to gas or water coning and low production rates. Results were not sufficiently encouraging to lead to future activity in the short term. Horizontal drilling technology evolved rapidly and in 1990, Oman embarked on a more ambitious program. The results, this time, were so impressive that the trial was extended and has led to almost continuous horizontal drilling. Some 100 horizontal wells per year are expected to be drilled for the foreseeable future. These wells exploit both clastic and carbonate reservoirs from Precambrian to Cretaceous age, thin and thick oil columns, light and heavy oil, and a wide range of reservoir quality. Multilateral drilling in Oman has also shown significant benefits in increased production rates, reduced costs and increased oil recovery from existing p...

Different data are required in order to establish a realistic reservoir model capable of predicting the dynamic field behaviour during the development stage of an oil field. Well testing is considered to be one of the most effective methods for obtaining these reservoir and wellbore data. Numerous analytical models are available and utilised in investigating vertical-well pressure transient tests, on the other hand, horizontal-well pressure transient tests have been considered as more difficult to analyse. In this work, well test data of a horizontal-well are simulated for homogeneous isotropic and anisotropic reservoirs and analysed in order to develop empirical correlations that rectify the vertical reservoir permeability estimated by well testing.

An adequate knowledge of any reservoir fluid PVT properties is essential for most types of petroleum calculations. These calculations include amount of oil in the reservoir, production capacity, variations in produced gas-oil ratio during the reservoir's production life, calculation of recovery efficiency, reservoir performance, production operations and the design of production facilities. PVT properties can be measured experimentally by using collected bottom-hole or surface samples of crude oils. But, the experimental determination of PVT is time consuming and very costly. In addition, even with the availability of PVT analyses, it is often necessary to extrapolate the data to field and/or surface conditions through the use of empirical correlations. Furthermore, geological and geographical conditions are considered very critical in the development of any correlation. But, universal correlations are difficult to develop. That is why correlations for local regions, where crude properties are expected to be uniform, is a reasonable alternative. In this study, experimental PVT data for North and South Oman crudes, statistical and artificial neural network (ANN) analyses are used to develop reliable PVT correlations. Comparisons with previously published correlations are presented.

Residual oil in sandstone is affected by mineral composition, clay matrix and cementing material. Matrix minerals affect the affinity of a fluid to spread on a rock surface significantly and in turn controls the fluid distribution within the pore spaces. At the interface between the rock surface and the contacting fluid, electrical charges are in the origin of the extent of phase wetness. Available framework grains, a dominant component of rock matrix, affect porosity and, hence, amounts of rock preferential wetness. Cement, clay matrix and quartz overgrowth, which make up for the rest of the grain population in a rock, influence wetness and, therefore, amounts of residual oil. In this paper, spectro-electromicroscopy (SEM) point-count technique in conjunction with neural network analysis were used to determine the effect of certains rock parameters on the amounts of residual oil following waterflooding operations. Using artifcial neural network, the intent was then to predict the extent of resid...

Gravity segregation in thick reservoirs, in particular, affects the distribution of hydrocarbon components in a fluid column. Given sufficient time, heavy molecules will migrate towards the bottom of the hydrocarbon column to form a mat of viscous oil. Compositional grading can be in the origin of miscalculation of reserves. In fields producing volatile oils with heavy ends, in particular, the oil formation volume factor (FVF) can vary significantly with depth. That can lead to overestimation or underestimation of the reserves depending upon fluid sampling depth. For that reason, subsurface sampling depth is critical and fluid sampling from different depths only can be considered as representative sampling. In this paper, assessment of compositional grading was explored using variation of reservoir fluid properties with depth. Different hydrocarbon column thickness have been tested to prove that grading will be enhanced for reservoir thickness exceeding 164 feet.