The Use of Chromate Desorption Systems to Optimize the Position of the Wells Relative to the Contact Boundaries During the Development of Oil Rim Fields

This paper presents a novel technology for identifying the inflow profile during the oil rim development using chromate desorption systems that makes it possible to solve one of the critical tasks related to long horizontal and multi-bottom-hole wells—optimizing the position of well relative to the contact boundaries to prevent early water breakthroughs and gas outs.

Evaluating Efficiency of Multilateral Producing Wells in Bottom Water-Drive Reservoir with a Gas Cap by Distributed Fiber-Optic Sensors and Continuous Pressure Monitoring

The main goal of the pilot job is to assess the risks of production by horizontal wells and multilateral wells with a close gas cap above and water layers beneath the main formation. The objectives are to monitor the total producing length of the wells using temperature and pressure surveillance. The results of monitoring were analyzed at different stages of development. An analysis was carried out by combining pressure and temperature data obtained while monitoring the production of multilateral wells. The well properties were determined using RTA and PTA. To assess the inflow profile, distributed temperature sensors in the wells were analyzed for the entire period of appraisal production. A feature of the research was the low contrast of temperature anomalies associated with fluid inflow. In addition, it was also revealed that the DTS absolute readings at the depth of the formation were affected by surface temperature, which required corrections and the use of relative readings in the calculations instead of absolute ones. The main feature of the pressure analysis was the short period of production. With such well completion geometry and reservoir properties of the layer, the radial flow could not be achieved during the whole test period. Despite these limitations, the dynamics of the total producing length of the well was determined. The initial value of the producing length was about 70% of the drilled length, then there is a slight decrease after 7 to 10 months of well production. By analyzing the fiber-optic temperature profile, an inflow profile was assessed. Based on the analysis of changes in relative temperature anomalies, the shares of inflow from the sidetracks were estimated. Several memory temperature / pressure gauges set along the horizontal section were used as an additional data source to monitor well parameters during the whole period of production. The difference in their readings was due to, among other things, the average flow rate in the section between the sensors, which made it possible to give an independent assessment of the inflow profile. Based on the results of the job performed, a number of risks and uncertainties were removed, including information on the total flowing horizontal length dynamics, which is a valuable input for full-field development planning. In addition, an express method of DTS data analysis has been developed for assessing the wellbore producing length without significant temperature changes associated with intervals of inflow.

Using DNA-Logging to Determine Inflow Profile in Horizontal Wells

The purpose of this work is to adapt and apply Next Generation Sequencing methods in oil and gas well field studies. Relatively recent NGS methods provide a description of a geological formation by analyzing millions of DNA sequences and represent an entirely new way to obtain information about oil and gas reservoirs and the composition of their fluids, which could significantly change the approach to exploration and field development. We present the results of pilot work to determine the inflow profile in a horizontal well based on DNA markers. The technology is based on the comparison of bacterial DNA from drill cuttings obtained while drilling with DNA from microorganisms of fluids obtained during production at the wellhead. Because of their high selectivity, individual microbes live only under certain conditions (salinity, oil saturation, temperature) and can be used as unique natural biomarkers. The comparison of DNA samples of drilling cutting and produced fluid allows for identification of the segment of the horizontal well from which the main flow comes, as well as identifying the type of incoming fluid (water, oil, gas) without stopping the operation process and without conducting expensive downhole operations. As a result of these studies, the microbial communities of the oil-bearing sands and formation fluids of the Cretaceous deposits (group BS) in Western Siberia were identified, and the relative numerical ratio of microorganisms in the formations was determined. It was shown that the microbiome diversity changes with depth, and depends on the lithological composition, and sequencing data obtained from cuttings samples correlate with data from wellhead samples of produced fluid. Thus, the practical applicability of DNA sequencing for solving field problems in oil and gas field development, in particular for determining the inflow profile in horizontal wells, was confirmed.

U-duct turbulent-flow computation with the ST-VMS method and isogeometric discretization

The U-duct turbulent flow is a known benchmark problem with the computational challenges of high Reynolds number, high curvature and strong flow dependence on the inflow profile. We use this benchmark problem to test and evaluate the Space–Time Variational Multiscale (ST-VMS) method with ST isogeometric discretization. A fully-developed flow field in a straight duct with periodicity condition is used as the inflow profile. The ST-VMS serves as the core method. The ST framework provides higher-order accuracy in general, and the VMS feature of the ST-VMS addresses the computational challenges associated with the multiscale nature of the unsteady flow. The ST isogeometric discretization enables more accurate representation of the duct geometry and increased accuracy in the flow solution. In the straight-duct computations to obtain the inflow velocity, the periodicity condition is enforced with the ST Slip Interface method. All computations are carried out with quadratic NURBS meshes, which represent the circular arc of the duct exactly in the U-duct computations. We investigate how the results vary with the time-averaging range used in reporting the results, mesh refinement, and the Courant number. The results are compared to experimental data, showing that the ST-VMS with ST isogeometric discretization provides good accuracy in this class of flow problems.

A Semianalytical Coupling Model between Reservoir and Horizontal Well with Different Well Completions

Although currently, large-scale and multilateral horizontal wells are an important way to improve the oil recovery in the unconventional reservoirs, the flow behavior of fluid from the reservoir into the horizontal wellbore becomes more challenged compared to the single small-scale horizontal well. One of the main challenges is that pressure loss from the well completion section and wellbore cannot be ignored in the coupling process between the reservoir and the horizontal well. In this paper, a new method is presented to solve the coupling flow between the reservoir and the horizontal well with different well completions. The new coupling model is compared with Ouyang’s model (1998) and Penmatcha’s model (1997), and the predicted data are consistent with each other at both early and late times. Meanwhile, four different cases have been proposed to verify the application of the new coupling model with different well completions, and the results indicate that the uneven inflow profile can be effectively alleviated via reasonable completion parameters and different well completions. Based on two types of flow-node units, it can quickly model and solve the coupling problem between the reservoir and the horizontal well with complex completion cases. It can also depict the inflow profile of the horizontal well with different well completions, which is conducive to understand the coupling process. The new coupling model can provide theoretical support for further optimization of completion parameters and well completions and finally improve oil recovery.