The following paper will detail the use of a high angle electric submersible pump (ESP) tangent in Northern Oklahoma Horizontal Oil and Gas Wells to maximize ESP drawdown at the sandface by enhancing gas separation at the ESP intake.
ESP performance expectations in horizontal wells can be severely diminished due to gas interference which can cause rapid head degradation in the ESP system. Understanding how the gravitational effects on the fluid stream can alter flow patterns in a horizontal wellbore is paramount to achieving the most cost effective solution for avoiding gas at the ESP intake while maximizing drawdown. Failure to consider how changes in wellbore deviation may alter fluid flow in deviated ESP operations before a well is drilled and completed may result in a completion design where the ultimate hydrocarbon recovery is partially inhibited due to gas interference.
Results detailed from Northern Oklahoma Horizontal Oil and Gas Wells indicate that the use of a high angle pump tangent in ESP operations was able to help accomplish greater than 90% gas separation at the intake of an ESP at bottom hole pressures less than 100 psia and gas-to-liquid ratios in excess of 2000 scf/bbl.
The application of advanced horizontal well technology has increased the demand for cost effective and reliable ESP solutions which mitigate the negative economic effects of prolonged downtime and repair costs associated with the challenges of operating in the modern horizontal wellbore environment. Conventional ESP design methodology for effective gas avoidance and deliquification in the vertical wellbore environment does not address the changes in multi-phase fluid behavior and flow patterns that are encountered as the wellbore is deviated in excess of 85 degrees from vertical.
Reservoir heterogeneity with high permeability zones attributed to channels, fractures, and large pore spaces can cause high water production in hydrocarbon producing wells. This paper investigates the performance of several particle-gel systems for near-wellbore (NWB) formation treatment to prevent or control the water production in mature oil fields. The particle-gel system consists of a polymer/crosslinker as the gel and silica flour as the particles that provide leakoff control. Fluid loss testing was conducted using sands of varying sizes and permeable filter disks, where the sand represents a gravel pack and the disk represents the formation. The filtrate volume was measured to determine the leakoff under different treatment and formation conditions. Effects of particulate concentration, pore space of the permeable filter disk, sand size, and temperature on the leakoff volume and the threshold-pressure, which must be overcome to initiate water flow, were studied. The experimental results reveal that filtrate loss decreases with increasing silica flour concentration and increases with increased pore size of the permeable filter disk, sand particle size, and temperature while the threshold pressure increases with increased silica flour concentration and decreases with increased sand particle size, pore size of the permeable filter disk, and temperature. Practical empirical correlations and charts are developed for fluid loss, pressure initiation for flow, and the critical silica flour concentration which can aid in selection of a suitable particle-gel system for effective NWB formation treatment. A methodology using these correlations and charts is presented for the design of optimal conformance control treatments for effective mitigation of water production in mature oil fields. A field case is also illustrated to demonstrate the importance of the developed empirical correlations in choosing suitable treatment fluids and evaluating the near-wellbore formation treatment under optimum application conditions.
Escobar-Remolina, J.C.M. (Ecopetrol S.A.) | Barrios-Ortiz, W. (Ecopetrol S.A.) | Franco-Sandoval, L. (Ecopetrol S.A.) | Sachica-Avila, J. A. (Ecopetrol S.A.) | McCoy, C. (Permian Production Inc.) | Rios-Recuero, R. D. (Imgeprom Ltda.)
In this work we show how using beam gas compressor technology, typically installed on a centrally located pumping unit, on six unprofitable wells, reduces greenhouse gas emissions to the atmosphere and increases oil production in the selected pilot area for this technology application.
As the wells produce and the natural strength of the reservoir drive mechanism decreases over time, the bottom hole pressure is reduced to the point where the wells are produced by artificial lift methods, being the mechanical pumping with sucker rods the most and frequent system used. These systems present several problems with time due to the backpressure in the casing restricts the oil and gas production. Additionally, in most wells with oil and gas production, gas is vented to the atmosphere to be burned, representing environmental problems and high operating risks.
After installing beam gas compressors on each well, its oil production rose on average by 35% and it was allowed to emit into the atmosphere, for a period of one year, 33 000 tons of CO2 equivalent. The Colombian state oil company, and its production engineers where the technology was implemented, are very satisfied because they have succeed to relieve restricting backpressure, capture and compress vented gas or avoid gas flaring and convert marginal wells in profitable ones, so the involved time and their costs were permanently removed. Beam gas compressors technology makes the six wells were profitable again and leverage field production with very few maintenance problems. This technology can be applied in other fields to wells with similar characteristics.
Ampomah, W. (Petroleum Recovery Research Center - New Mexico Institute of Mining and Technology) | Balch, R. S. (Petroleum Recovery Research Center - New Mexico Institute of Mining and Technology) | Grigg, R. B. (Petroleum Recovery Research Center - New Mexico Institute of Mining and Technology)
Even though computer power has increased dramatically over the years it is still essential to upscale detailed geological models before reservoir simulation, to decrease simulation time and cost. This paper presents the upscaling of a high resolution geological model constructed for a reservoir in the Anadarko basin. The Dykstra-Parsons coefficient computed indicates a highly heterogeneous and complex reservoir.
This work compares different upscaling algorithms for both primary and secondary reservoir depletion processes. Also, the effects of different boundary conditions were tested. Numerous upscaling ratios were studied to ascertain ideal upscaled grid sizes. Prior to property upscaling, quality check techniques which include cell volume, cell angles and cell inside out computations were applied. This ensured consistency with the fine-scale model and reduced simulation errors. Additional quality check techniques were applied to the coarse models after the property scale-up. Simulation results and volume computations from the fine model were used as a benchmark for the study. Several coarse simulation models were developed and compared to the fine-scale model to study the effect of upscaling techniques on the quality of simulation results. The deviation of coarse simulation results from the benchmark were statistically quantified and ranked according to the respective upscaling algorithm. The closest coarse model to the fine scale was used to construct a history match.
The results showed clearly that different depletion processes had significant effects on the upscaling techniques employed. Nearly all of the algorithms worked well for primary depletion processes, for example, with less favorable outcomes for the waterflood utilizing the same models. Simulation results were very sensitive to both the type of boundary condition employed and the upscaling ratio. The quality checks ensured good orthogonal grid geometry, which eventually reduced overall simulation errors and saved simulation time. The methodology presented in this paper establishes a road map to follow when upscaling geological models to ensure accuracy in reservoir modeling.
Elasticity in the Woodford is Anisotropic in nature. From the upper woodford, middle, and lower sections, the Youngs modulus varies. In this case, two properties are mostly common: Ductility and Brittleness. This paper will focus on these rock properties, their effect on hydraulic fracturing and how to better manage them.
The upper woodford is mostly brittle (see
Optimal design of matrix acidizing treatments in long horizontal wells represents a technical challenge for stimulation engineers. Acid coverage and distribution are particularly challenging because differences in formation permeability can be a predominant feature in horizontal wells. If acid is not effectively diverted in formations with high permeability anisotropy, some treated zones may become acid sinks while other zones are left with inadequate acid stimulation. Acid coverage and distribution depend on chemical and physical processes at different length scales. In the microscopic or pore scale in carbonate formations, acid creates flow paths of high permeability or wormholes which can affect the further penetration of the acid treatment downhole. In the macroscopic scale, fluid hydraulics in both wellbore and reservoir affect acid distribution as well.
In this paper, we present an integrated model in both the microscopic and macroscopic scale to simulate multistage acidizing treatments in limited-entry and open-hole long horizontal wells. We propose a modified semi-analytical model to describe the wormholing phenomena and chemical diversion by using core flow test data. The reservoir heterogeneity in both vertical and horizontal directions is taken into consideration in this model. In addition, we establish a dynamic wellbore hydraulics model to characterize the fluid mechanics inside the wellbore with considerations for acid distribution, pressure drop due to friction loss, fluid rheology and fluid flow behavior.
The integration of the elements mentioned above makes of this model a powerful tool to optimize critical parameters for matrix treatment design and distribution such as treatment interval length, diverter and acid volume, number of stages, and optimal rates. We present a case study to investigate the effects of chemical diversion, acid injection rate and volume on the performance of the treatment. The results of acid distribution, wormhole length and skin factor for each treatment interval as functions of time are analyzed. The evolution profiles of wellbore hydraulics during the acidizing treatment are also discussed.
This work introduces a new method to analyze the flow of fluids induced by one rotating cylinder within a substantially cylindrical space. This analysis is useful to either emulate the behavior of the flow of fluid during gravel pack or cleaning/drilling operations under the assumption of negligible effect due to a low advance-velocity or drilling-bit penetration-rate. The new method is based on the use of a non-dimensional coordinate system that enables the analysis of eccentric rotating pipes at small and large eccentricities and the Reynolds number. The eccentric annulus between two cylinders is mapped into concentric annuli by a bilinear transformation that is used to generate the coordinate system here discussed. Advantageously, the polar coordinates system is fully recovered from the discussed coordinate system once the eccentricity is set to zero.
The two- and three-dimensional linear momentum equations, mass conservation, and the particular incompressibility condition are expressed in terms of the discussed coordinate system.
To demonstrate the effectiveness of this method, the set of linear momentum equation and mass conservation for a two-dimensional steady-state flow of incompressible Newtonian fluid within an annular space at different eccentricities are asymptotically solved by using the perturbation method and compared with the analytical solution obtained by
The potential applications of this method to analyze the flow in gravel pack applications, to determine the cleaning effectiveness in fully eccentrically tubulars placed in horizontal wells and the abrasive effect observed in rotational drillstrings are also proposed for future research.
The large fluid and sand volumes associated with multi-stage, horizontal shale fracture completions have placed a major burden on the operating efficiency and integrity of surface equipment designed to handle sand-laden flowback. Many methods have been attempted to reduce and/or eliminate sand production during flowback and ongoing operations but due to a variety of flowing conditions sand flow to surface is inevitable. Talisman has worked extensively on implementing the use of sand probes to effectively monitor and mitigate incidents related to sand erosion of surface piping related equipment. This simple, low cost solution has made a major impact on Talisman's operating philosophy.
As the use of sand probes was not part of Talisman's standard wellsite design, testing was required due to the occurrence of multiple sand related incidents following removal of flowback equipment. Although sand flow is greatly reduced following an initial period of flow (30 to 60 days), the slugging nature of horizontal wells provides a significant risk for unexpected large quantities of sand to damage permanent separation equipment, surface piping and valves. Installing sand probes has successfully demonstrated the ability to shutdown wells prior to compromising the mechanical integrity of surface piping/facilities.
An initial pilot test was performed on several wells to determine whether or not sand probes were capable of providing adequate indication of erosive flow conditions. This paper details those tests and the results thereof. As the probes proved to be functional, Talisman now has over 100 installs in its Marcellus operating area.
Sand probes, although not a new technology, did prove to be challenging in this application. Several changes have been made since the first design in order to improve performance. In addition, much emphasis was put on the operating philosophy of the probes and actions required following device trips. This paper will share that information.
A high percentage of rod pump wells globally experience issues caused by production of a high amount of solids. Premature wear of pump components and stuck pumps are two leading failure modes caused by production of solids. Over the years industry has tried to solve these problems by introducing special coating materials for the wetted parts of rod pumps as well as developing special pump designs. However, currently available sand resistant technologies still lack reliability.
An innovative sucker rod pump with an integral filtering screen was developed and tested to address issues with production of high volumes of solids. This technology allows for increased plunger and barrel run life and has been successfully tested in numerous wells. This paper discusses the details of this new technology and the proven benefits based on field trial results.
The Woodford shale formation of Oklahoma is difficult to evaluate and forecast for production. Horizontal wells can often be inconsistent with offset wells, either in production rate or in expected ultimate recovery. The costs of these wells can vary greatly based on the cost and effectiveness of the fracture treatments used. Treatment can be difficult, and production rates do not always indicate open flow paths to the well.
Various logging techniques were applied in an attempt to overcome some of these treatment issues. Ideally, the imposed treatment will create a large surface area within the formation with continued, open flow paths from the contact surface in the reservoir to the wellbore. Because this is a rock mechanical problem, logs that can deliver a solution for relative rock mechanics were added to the logging program. Dipole sonic logs delivered the most consistent solution.
The paper provides a case study in which these data were applied in the Woodford formation in Oklahoma. In this study, a vertical pilot hole was drilled, dipole sonic logs were run, and rock mechanical values were calculated. The dipole sonic logs were run in casing in the horizontal wellbore. Anisotropy was calculated from these data. The fracture treatments were designed using rock mechanical information from both data sets.
This paper compares the results of the pilot well data with an offset well in which the acquired data were not used to alter treatments and initiation locations. Also, a comparison to an offset well is included, where dipole sonic in the horizontal were the only data acquired. In both cases, the better data set resulted in better completions.