Both the surface and the pump dynamometer cards are used to analyze sucker rod-pumped wells. Diagnostic pump card loads are calculated using the wave equation from the measured surface dynamometer load and position. The pump plunger fluid load, Fo, applied to the bottom of the rod string is directly related to difference in pressure across the plunger over the plunger area. Typical pump card loads plot near zero load when the traveling valve, TV, is open during the down stroke. When the standing valve, SV, is open during the upstroke the pump card loads should plot near fluid load determined using the pump intake pressure from a fluid level measurement. An expected fluid load maximum load line can be calculated by setting the pump intake pressure equal to zero.
The diagnostic pump card loads can be compared to these three reference load lines 1) Zero line, 2) Fo line from Fluid Level and 3) Maximum Fluid Load, Fo max, line. Certain downhole pump problems can be identified based on the location of the pump card loads with respect to these three load reference lines. If no load transfers between the TV and SV, then the diagnostic pump card becomes a flat shape. The location of the flat pump card can be used to determine if there is 1) the traveling valve could be stuck open, 2) a deep sucker rod string part occurs near the pump depth 3) the rods could be parted at a depth above the pump, 4) tubing could be dry, or 5) the SV could be stuck open.
If the pump intake pressure is low then the pump card load on the upstroke should plot near the Fo max reference load line. At a glance the location of the upstroke pump card loads can be used to estimate the pump intake pressure. Excessive downhole friction is indicated by the pump card displaying down stroke loads considerably below zero and upstroke loads substantially above the Fo from Fluid Level reference lines.
Incomplete pump fillage is often associated with a "pumped-off well", meaning that the pump displacement exceeds the production capacity of the reservoir. There are other causes of partial liquid pump fillage: gas interference or the presence of a flow restriction in the annulus or excessive pressure drop at the pump intake.
This paper describes analysis methods used to compare the pump card diagnostic loads to the reference load lines. The analysis of the data can be used to identify the reason for lack of pump action or the cause of incomplete pump fillage. Several example field datasets will combine dynamometer and fluid level records to identify the source of the problem and presents recommendations for possible solutions. Use of downhole pump load and position is the basis of pump card diagnostic analysis and troubleshooting.
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 continued surge of development activity in unconventional resource plays over the past years has led to a significant increase in newly hired engineers within the oil and gas industry. As operating and service companies increase hiring rates with these increasing activity levels, field operations often take priority to training and development of employees, which can result in a workforce with limited training beyond that which they receive in their first year or two with the company. At the same time, many operators are increasing their focus beyond operational efficiency and more toward maximizing hydrocarbon production rates and recoverable reserves through better reservoir understanding and advanced technical solutions. This optimization process, particularly true for unconventional reservoirs, requires engineers to have a broad multidisciplinary knowledge and to be able to participate in a collaborative work environment.
Therefore, the question can be posed of where this leaves engineers with limited advanced training. This paper describes a training program for early to mid-career engineers offering a unique learning experience intended to deliver an advanced skill set with respect to exploitation of unconventional reservoirs. After successfully completing their initial training, students enter the advanced program and are offered a curriculum including the areas of subsurface understanding, completion design, and reservoir optimization. The students develop expertise in unconventional well completions, providing value to well operators and teams with which they interact while gaining professional growth opportunities during the process.
Liquid loading is the inability of a riser or gas well to produce liquids, resulting in reduction of gas production in mature gas fields. Mechanisms describing liquid loading initiation are not well understood for inclined pipes or deviated wells. Knowing the effect of pipe inclination over the liquid-loading initiation will help for the development of a predictive tool for flow assurance, well production forecast as well as remediation techniques enhancing gas production.
An experimental study of low liquid loading has been conducted for 90°, 75°, 60° and 45° inclined pipes. Air/water flow in a 3-in ID pipe has been investigated. Pressure gradient and average liquid holdup were measured. Visual observations with high and low speed cameras have been recorded to identify flow patterns and liquid film behavior for each test point. Pipe inclination effects on critical gas velocity for flow pattern transition have been investigated.
The critical gas velocity represents the maximum gas flow rate where the liquid loading is observed. This critical velocity increases as pipe inclination deviates from vertical. Pressure gradient fluctuations and liquid film flow behavior are closely related with liquid loading initiation. As the pipe deviates from vertical and owing to the increasing liquid film thickness at the bottom of the pipe, slug and churn flow patterns are promoted. Therefore, the existing critical velocity prediction models, which ignore the circumferential variation of film thickness, produce significantly different values of critical velocities when compared with the experimental data.
Liquid loading is one of the main problems that the industry faces during the production of natural gas wells and transportation of low liquid loading gas-liquid flow through a riser. This study serves as a foundation for future model developments to avoid and remedy liquid loading related problems in risers and gas wells.
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.
Improved production forecasting allows completion engineers to compare cause and effect on alternative completion strategies and reservoir managers to optimize spacing and determine reserves. Paramount in production forecasting is recognition of the transition from linear flow into the fracture face to boundary dominated flow caused by the distance of investigation from adjacent fracture facies along the horizontal wellbore to meet. If all completions were the same and permeability constant, this transition point would be identical. Or if permeability and distance between fracture stimulation treatments were known, the time to this transition could be calculated. Without the constant reservoir/completion assumption and/or known reservoir/completion information an alternative approach can be employed using a stochastic technique exploiting offset well data where this transition can be determined. This study looks at horizontal oil wells that have been producing, approximately three to seven years, in the Bakken Shale, in McKenzie and Williams Counties, North Dakota. The technique utilized in this study is based on a finite conductivity model match of reciprocal rate versus cumulative production, this study uses monthly production data from public data records.
Inherent in this method model is the simultaneous fit of the boundary dominated Arps' b exponent during boundary dominated flow and the transition point. There will be an optimum fit of the boundary dominated flow production rate yielding an instantaneous rate and instantaneous decline that match the rate and decline at the end of linear flow. This linked Arps' method ensures a model continuum while honoring simulation models and field observations for finite conductivity fractures.
Once the transition time (end of linear flow/beginning of boundary dominated flow) has been determined a statistical approach was used to determine the probability that transition time will occur at various times using approximately 70 horizontal wells.
The latter in the well's life this transition occurs the higher the reserves. So for a well still performing in a linear flow regime, a probabilistic approach can be applied to ascertain proved, probable, and possible reserves.
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.
The Permian Basin plays an important role in the US oil and gas industry with production of one-fifth of all US domestic oil and gas. With the development of hydraulic fracturing technology, the low permeability oil-bearing sands of the Third Bone Spring formation have proved to be profitable. Multistage hydraulic fracturing in horizontal wells through multiple reservoir sands allows production of hydrocarbon from multiple reservoirs at the same time while improving the hydrocarbon flow significantly in low-permeability formations. As drilling activity in the Third Bone Spring continues to increase, there is still a lack of full understanding of fluid flow in unconventional hydrocarbon reservoirs producing through hydraulic fractures. Our reservoir characterization and simulation modeling study is the first stage of a full field development study. The main goal of this study is to investigate general behaviors of the Third Bone Spring formation under common wellbore conditions such as multistage hydraulically fractured horizontal wells. This study also aims to initiate a larger-scale full reservoir simulation study for the field development plan of the region by showing the value of performing reservoir simulation with the available data.
Available data from multiple disciplines were used for the study, including well placement, petrophysics, geology, well completion, and stimulation. The data were then processed and used to build a reservoir simulation model that represents the Third Bone Spring sands. Actual data from representative vertical and horizontal wells in a defined area of interest were used to build the static and dynamic model. Other well trajectories were added to the model to investigate the production behaviors of different wellbore scenarios. The simulation model was run, and the results indicate that the hydrocarbon production is sensitive to reservoir properties, hydraulic fractures, and wellbore footage in the reservoir sands.
As expansion into unconventional reservoirs continues, one of the key drivers of well performance has become completion efficiency. Much of this efficiency centers around finding the completion strategy that effectively drains the entire lateral in a horizontal wellbore. Different fracture spacing and perforation schemes have been attempted to try and accomplish maximum coverage with minimal interference between stages. However, even as fractures are planned with a particular spacing, there is no guarantee that every perforated interval will lead to a productive fracture. One of the key questions has been: How many of the fractures are actually contributing to production? Numerous authors have developed methods for estimating this number, and a small set of diagnostics tools are currently being used in the industry to evaluate fracture placement.
In production prediction workflows the number of contributing fractures is estimated using data that are readily available, such as completion designs, fracture propagation models, or production profiles.
With increasing oil and gas exploration and production activities taking place, concern about how environmental issues are addressed grows. While industry has made great strides in the protection of the environment, various challenges still exist. The Environmentally Friendly Drilling (EFD) Program provides unbiased science on technologies that are designed to address environmental issues. The EFD Scorecard was created to be a voluntary, consensus-based tool that can measure how industry addresses environmental and societal issues. The Scorecard provides a common lexicon enabling all stakeholders to understand the level to which these concerns are addressed.
The EFD Scorecard methodology is designed to document how issues such as air, water, site, waste management, biodiversity/habitat, and societal impacts are addressed. It is intended to be an adaptive ecosystem services management tool that will assist operating companies in planning and implementing good practices to manage operational risks. It can be used to objectively assess operators' environmental performance and provides a means to increase environmental and societal awareness within an organization. The Scorecard has been tested on site in different locations in the United States and Canada. These review processes identified additional attributes to consider for inclusion and/or elimination to further ensure relevant information was being examined.
Issues involving air, water, site and societal/community disturbances potentially alarm stakeholders who may not understand that numerous environmentally friendlier technologies are currently being researched, developed and used to address such matters. Air and water are a focus for many, particularly with attention to increasing regulatory requirements. Several operators go beyond what is required, taking steps to lessen effects. Biodiversity management is frequently considered within the reclamation process. Many operators and service providers are mitigating effects to wildlife habitats by incorporating proactive measures. The Scorecard enables a methodology to be employed that documents existing, cost effective, proven technologies, processes and systems used to address environmental and societal issues associated with energy development. Industry can gain powerful and much needed insight in relaying their efforts at addressing environmental issues throughout E&P operations. As the demand for oil increases, a tool to measure and share the performance and commitment of operators can help allay unease about transparency. Benchmarking best management practices in action and making such data available can also improve communication with all stakeholders.
This paper aims to provide an overview of a tool for operators that will help open the doors of communication to all of their stakeholders. The EFD Scorecard will provide the unbiased data in understandable and approachable terminology that has been vetted by industry, environmental groups, academia and NGO's, enabling the O&G industry to reach out to communities surrounding operations and engage them in dialogue.