Performance of 15 Years of Hydraulic Fracturing of Oil Wells in South of Oman

The first application of Hydraulic Fracturing in the South Oman started in 2000 to enhance water disposal wells. In 2004 the first oil wells were frac'ed. Although the technology was deployed many times, it never grew into a conventional practice. From 2004 to 2017 on average 5 Oil Wells were hydraulically fractured on yearly basis. In November 2017, a Hydraulic Fracturing Maturation & Expansion Workshop was conducted with the vision of growing the application by applying new frac concepts. A focused effort was initiated to drastically reduce cost, and simultaneously increase the scope by executing larger frac campaigns. The first hydraulic fracturing campaign introducing the frac new concepts, started end 2018 and a rapid growth from 5 wells per year to 45 wells per year was anticipated in the next three years. This large growth of scope relied on a steady supply of frac candidates and needed to be supported by screening and selecting processes that are fit for purpose in finding candidates. Although more than a hundred wells had already been frac'ed wells, selection of the most appropriate wells for stimulation was and remains one of the greatest challenges. A frac performance database was created for over 100 wells that had been hydraulically fracture stimulated to date. Recognizing that the frac performance depends on many variables ranging from subsurface properties to surface execution of the frac job, the size of the dataset proved to be too small to find correlations using sophisticated multivariable regression methods. Instead, the dataset was analyzed through careful investigation and evaluation of each frac job. In this paper the net oil gain will be used as the key success criteria i.e., value driver to demonstrates how effective the frac is achieving its business objective. Some 40% of the producers had been producing from the same zone before the hydraulic fracture stimulation. This provided the opportunity to understand the efficiency of the stimulation in terms of the "stimulation ratio" i.e., measuring the net oil gain. This paper will focus on investigating the suitability of frac'ing the reservoir based on the initial production variables; Gross Rate and BS&W. Also, this paper will discuss benefits and impacts of Hoist versus Coiled-Tubing clean-out on the frac delivery process and compare the frac performance. To date, the project demonstrated that hydraulic fracturing at low cost, can be applied as a viable development concept for producing oil wells, with the potential unlock additional and new reserves. Significant folds in production increase are possible from 2x to 7x.

A Novel Mathematical Model for Fracturing Effect Evaluation Based on Early Flowback Data in Shale Oil Reservoirs

For shale oil reservoirs, the horizontal well multistage fracturing technique is mostly used to reform the reservoir in order to achieve economic and effective development. The size of the reservoir reconstruction volume and the quantitative characterization of the fracture system are of great significance to accurately predict the productivity of shale oil wells. There are few flowback models for shale oil reservoirs. To solve this problem, first, a physical model of the simultaneous production of oil, gas, and water in the early flowback stage of shale oil development is established using the material balance equation for a fracture system. Second, the physical model of the underground fracture system is simplified, which is approximately regarded as a thin cylindrical body with a circular section. The flow of the fluid in the fracture system is approximately regarded as radial flow. In this model, the expansion of the fluid and the closure of the fracture are defined as integrated storage coefficients to characterize the storage capacity of the fracture system. Then, the curves illustrating the relationships between the oil-water ratio and the cumulative oil production and between the gas-water ratio and the cumulative gas production are drawn, and the curves are used to divide the flowback stage into an early stage and a late stage because the flowback process of shale oil wells exhibits obvious stage characteristics. Finally, the reservoir reconstruction volume and the related hydraulic fracture parameters are estimated based on the material balance method, and the rationality of the model is verified via numerical simulation. The interpretation results of this novel model are more accurate, making it an effective way to evaluate the hydraulic fracture parameters and transformation effect, and it has guiding significance for the evaluation of the hydraulic fracturing effect in the field.

An ESP Production Optimization Algorithm Applied to Unconventional Wells

The objectives and Scope is to evaluate the feasibility of a Production Maximization algorithm for ESPs on unconventional wells using projected operating conditions instead of current ones, which authors expect will be crucial in adjusting the well deliverability to optimum frequencies on the rapidly changing conditions of tight oil wells. Actual production data for an unconventional well was used, covering from the start of Natural Flow production up to 120 days afterwards. Simulating what the production would be if a VFD running on IMP Optimization algorithms had been installed, new values for well flowing pressures were calculated, daily production scenarios were evaluated, and recommended operating frequencies were plotted. Result, observations, and conclusions: A. Using the Intelligent Maximum Production (IMP) algorithm allows maximum production from tight oil wells during the initial high production stage, and the prevention of gas-locking at later stages when gas production increases. B. The adjustment of frequency at later stages for GOR wells is key to maintaining maximum production while controlling free gas at the intake when compared against controlling the surface choke. Novel/additive information: The use of Electrical Submersible Pumps for the production of unconventional wells paired with the use of a VFD and properly designed control algorithms allows faster recovery of investment by pumping maximum allowable daily rates while constraining detrimental conditions such as free gas at the intake.

Using artificial intelligence methods for shear travel time prediction: A case study of Facha member, Sirte basin, Libya

Shear wave travel time logs are major acoustic logs used for direct estimation of the mechanical properties of rocks. They are also important for prediction of critical drawdown pressure of the reservoir. However, core samples are sometimes not available for direct laboratory measurements, and the time-consuming dipole shear imager tool is generally not used. Hence, there is a need for simple indirect techniques that can be used reliably. In this study, cross-plots between the available measured shear travel time and compressional travel time from three oil wells were used, and three artificial intelligence tools (fuzzy logic, multiple linear regression and neural networks) were applied to predict the shear travel time of Facha member (Gir Formation, Lower Eocene) in Sirte Basin, Libya. The predicted times were compared to those obtained by the equation of Brocher. The basic wireline data (gamma ray, neutron porosity, bulk density and compression travel time) of five oil wells were used. Based on principle component analysis, two wireline data sets were chosen to build intelligent models for the prediction of shear travel time. Limestone, dolomite, dolomitic limestone and anhydrite are the main lithofacies in the Facha member, with an average thickness of about 66 m. The simple equation gave 87% goodness of fit, which is considered comparable to the measured shear travel time logs. The Brocher equation yielded adequate results, of which the most accurate was for the Facha member in the eastern part of the Sirte basin. On the other hand, the three intelligent tools’ predictions of shear travel time conformed with the measured log, except in the eastern area of the basin.

Development of polymer emulsions stabilized with anionic polyelectrolytes

The colloidal-chemical principles of the formation of reversibly reversible microemulsions based on compositions of anionic polysaccharides, higher fatty acids, and nonionic polyoxyethylated surfactants have been investigated. The structural formula of the interpolymer complex in the “polyelectrolyte - surfactant” system was proposed, and the molar ratios of the components were determined. The effectiveness of the developed polymer emulsions as drilling fluids for the construction of oil wells is shown.

Experimental Study on Type and Accuracy Optimization of Sand Control in Sand-Producing Heavy Oil Well

This paper proposes a set of methods for selecting the type of sand control screen and optimizing the accuracy in heavy oil Wells, which take into account the requirements of sand control and productivity protection in heavy oil Wells. Sand retaining experiments are carried out with slotted screen, wire wrapped screen and metal filter screen under the condition of oil and water mixed sand carrying flow. In order to optimize the sand control screen suitable for heavy oil well, this paper uses the weighted average method to quantitatively evaluate the flow performance, sand retention performance and oil conductivity of the screen. Then, repeat the experiment by changing the accuracy of the screen to optimize the accuracy. The experimental results show that the permeability of the three kinds of sand control screens is about 2μm2 when only heavy oil plugging occurs. Under the combined plugging action of formation sand and heavy oil, the slotted screen has the highest permeability, and its conductivity to heavy oil is 10% higher than that of the other two screens. The silk-wound screen has the best sand retention performance, with a sand retention rate of more than 90%. Through the quantitative evaluation of the sand control performance of three kinds of screens in different production stages of heavy oil Wells, the slit screen is selected as the optimal screen. For simulated formation sand with a median particle size of 250μm, the optimal sand control accuracy is 200μm. This paper provides a quantitative optimization method of screen type and accuracy for sand control design of sand-producing heavy oil Wells, so as to maximize the productivity under the premise of ensuring sand-producing control of heavy oil Wells.