The benefits of the Beam Gas Compressor® for rod pumped wells has now been modified to a standalone version. Allowing the technology to facilitate a broader range of operations and objectives.  Historically, the Beam Gas Compressor® has been installed on pumping units and utilizes the prime mover of the pumping unit to drive a piston inside a proprietary designed cylinder. This paper describes how this technology has been adapted to a standalone compressor installation, how the changes allow more versatile uses and how the technology compares with other types of compression.

Typical production profiles using a decline curve are then used with IPR equations to predict IPR expressions with time into the future.  Then using application rules such as limiting depths and rates, gas separator feasibility for pumps and flowing well and gaslift calculations from Nodal programs, Artificial Lift possibilities are mapped out into the future.  The techniques are not limited to the production profiles used as an example. 

Wireless high-frequency motor power-current-voltage measurements are used to analyze the electrical and mechanical performance of pumping units.  The sensors can be mounted permanently in the electrical box with a water-tight connection on the side of the electrical box for attachment of a small plug-in radio for wireless communication to a PC base station.  These measurements can be performed without opening the electrical box.  In addition, starter boxes without internal sensors can be analyzed using portable sensors that require opening the box and attachment of two current and three voltage sensors.

TAM Software in the PC receives and analyzes the data to determine power usage, power generation, pumping unit balance, gear box upstroke and downstroke torques, motor loadings, and power line loss.   Power line loss is an analysis performed to analyze the power line loss between the electrical system and the pumping unit motor.  The counter-weight movement for gear box balance is determined easily without use or knowledge of the pumping unit dimensions. 

Many operators in the Permian Basin have moved from drilling vertically to developing leases with horizontal drilling.  After implementing a horizontal drilling program, three critical challenges emerge:  1) selecting the most efficient means of initial production; 2) using a rod pump design without experiencing gas interference or losses in volumes; and 3) handling a horizontal well at pumped-off conditions.  Drawing the well down as quickly as possible is ideal for generating the best economics. The initial investment and operating costs of the artificial lift system must also be considered when performing economic analysis.  Rod pumping horizontal wells to produce the high rates that the model describes is challenged by gas interference which has resulted in the following: rod and tubing wear, upper buckling tendencies, increased man hours trying to resolve problems, and a loss in production.  When pumped off conditions occur while rod pumping from the kick off point, a noticeable decline in production can be observed.  In low pressure reservoirs, lowering the pump into the curve can prove to restore or even increase production rates.  By studying past cases of producing Yeso horizontal wells in the New Mexico Shelf Platform, COG has been able to select an optimally sized ESP, smoothly convert to a rod pumping system to achieve pumped off conditions, and continue to produce in the curve to avoid losses in production.

When using artificial lift, namely sucker rod pumps, there are three major factors to consider when trying to control and optimize production: elasticity, viscous friction and mechanical friction. The Modified Everitt-Jennings uses an iteration on dual damping factors to approximate the correct amount of viscous friction to be removed to mimic the energy lost through the viscous forces imparted on the outer diameter of the rods by the fluids. A precise Fluid Load Line Calculation provides a concavity test to diagnose the presence of mechanical friction.

Secondly, in order to maximize production and prevent rod string damage, pump-off control technology must be used in conjunction with sucker rod pump installation. The most accurate type of pump-off control is one using pump fillage. The Modified Everitt-Jennings combines an in-depth stress analysis with a powerful Pump Fillage Calculation, which outputs correct pump fillage regardless of downhole conditions present.

In this paper, a complete methodology for controlling sucker rod pumps is presented. This methodology combines state of the art, innovative methods that smartly and efficiently automate the control of sucker rod pumped wells.

In the case of a vertical well, the rod string can be compared to an ideal slender bar. Therefore the propagation of stress waves occurring from cyclic loading and un-loading during a pumping cycle becomes a one dimensional phenomenon.

The most accurate way of computing downhole data, is therefore by solving the one-dimensional damped wave equation. The Modified Everitt-Jennings algorithm combines finite differences with other state of the art innovative algorithms to provide precise downhole data, accurately reflecting present downhole conditions.

In the 1990’s, Sandia National Laboratories were contracted to measure actual position and load data at different depths of the rod string through a series of downhole tools.

In this paper, results from the Modified Everitt-Jennings methodology are compared to actual field measurements, captured by the Sandia National Laboratory experiment.

The Electronic Downhole Load Cells (DHLC) was used during the mid-1990s to acquire downhole dynamometer data.  The unique DHLC was mounted at a desired location in the rod string (usually between two rod tapers).  Dynamometer data was collected while the well operated.  SANDIA coordinated collecting DHLC data on six (6) different types of wells.  The petroleum industry provided wells and SANDIA collected, de-coded and presented the data.  NABLA and others concurrently acquired the surface Dynamometer measurements.  DownDYN software developed by SANDIA was used to display and export the collected data.

The dynamometer data acquired at each rod taper for each well will be displayed.  The DownDYN software is no longer supported by current Windows Operating system.  This valuable information will be lost, if the DownDYN software is not modernized.  Downhole Load Cell data measured at the pump resolved the display of the downhole pump loads. This paperwill discuss the true/effective load argument for display of downhole dynamometer data.  

A new term “Equivalent Gas Free Pump Fillage Line” represents the amount of liquid fillage inside the pump chamber when the traveling valve opens during the down stroke.  Adjustments for gas in solution, slippage, free gas, and compressibility of liquid due to pressure and temperature are required to determine the amount of stock tank liquid produced per day for a selected stroke.

Field dynamometer data from eight different wells will be used to compare the calculated to measured surface oil and water production volumes.   Equivalent gas free pump fillage line will be shown for each well’s representative pump card.

The pump card calculated gas produced up the tubing and the acoustic fluid level tested free gas produced up the tubing/casing annulus are used to determine system gas separation efficiency.  This enhanced analysis technique allows answering many complicated questions concerning oil, water, and gas production with respect to the downhole pump card.

We explore how minor modifications in routine usage of typical rod pumping equipment may improve the performance of rod pumped wells; e.g. how initial proper selection and implementation of polished rods and can limit well failures.  Also discussed are pump design changes to mitigate common pumping problems, and why standardized pump designs are not over-all beneficial to producing wells.  Additionally, we illustrate that standardized or “common” downhole design limits production rates

This paper will highlight the use of high liquid volume plunger lift to date in the Southern Delaware Basin.  This method of lift was first considered by COG Operating, LLC in an effort to bridge the gap for taking a well from flowing to rod pump.  Historically in the Southern Delaware Basin this was accomplished with high cost electric submersible pumps.  One of the criteria for success was that plunger lift would be able to replace the electric submersible pumps and economically maintain the well on its natural decline.   To date, COG has eight wells that have been successfully operating with high volume plunger lift. Representative decline curves will be presented, along with operating pressures and histories on the successful wells in the project.  The paper will be presented both from the prospective of the operator and then operating criteria from the vendor that have made this project a success.

Knowledge of the magnitude of different components of mechanical torque acting on the gearbox is crucial for the design and analysis of sucker-rod pumping installations. Gearbox torques include the torque required to drive the polished rod and the torque used to rotate the counterweights. In addition to these, inertial torques arise in those parts of the pumping unit that turn at varying speeds. As shown in the paper, all torque components are functions of the crank angle, consequently their exact calculation necessitates the knowledge of the crank angle vs. time function. This circumstance, however, complicates torque calculations because contemporary dynamometers, used to acquire the necessary operating data, do not provide any information on the variation of the crank angle during the pumping cycle. The paper introduces a solution of the problem and presents an iterative calculation of the crank angle vs. time function from dynamometer data. Based on this function crank velocity, acceleration, as well as beam acceleration are easily found and all necessary gearbox torques can be evaluated. The paper describes the details of the developed calculation model and presents example calculations.

The early detection of "sweet spots" for oil/gas well site selection and fracturing in shale reservoirs is a challenge for many operators. Most of the time, unique parameters are utilized (i.e. brittleness based on geomechanical and geochemical parameters) to determine the "sweet spots" for well site placement. Additionally, the fractures are generally placed equidistantly. 

This may create short transverse and/or non-planar hydraulic fractures that are problematic during hydraulic fracturing and may create suboptimal production.

This technology utilizes an integrated approach to site selection and fracture sequencing that allows for the optimal productivity of the well. 

This integrated approach utilizes both petrophysics and geomechanical data to develop a Fracturability Index to guide well site selection and fracture positioning in unconventional shale plays. It also, introduces an optimization approach based on mathematical formulations to guide scheduling of fracturing operations in big resources.

In the hydraulic fracturing industry, it has been a long-time problem and struggle to accurately track the usage of chemicals on fracturing site and make proper management decisions.  The manual approach has measurement error and the chemical inventory information cannot be accessed by people such as directors or managers who may not be on site but need the critical information for decision-making. Obtaining chemical inventory information automatically and making it available on-line would significantly save material costs, enhancing asset management efficiency. In a designed system, a guided-wave radar level sensor is used to measure the chemical level and the chemical inventory data are updated on an internet server through the satellite internet in the control van, making the information available on-line for engineers, managers and clients. The proposed monitoring and inventory system will greatly enhance asset management efficiency and reduce cost for the oil and gas industry. 

Worker safety is a vital part of the oil and gas industry. Enviroklean Product Development Inc. (EPDI) increases worker safety through education and training on Naturally Occurring Radioactive Material (NORM). EPDI offers several different training levels including NORM awareness, NORM worker, NORM surveyor and NORM Radiation Safety Officer (RSO). Education combined with enhanced surveys and analysis of NORM by gamma spectroscopy allows for accurate readings of NORM on a job site. The gamma spectrometer is an instrument that measures the energy and intensity of radiation in a sample such as soil, scale or sludge.  EPDI in conjunction with the Nuclear Engineering Teaching Lab at the University of Texas has developed a gamma spectrometer and computer program that allows for real time on-site results within 15 - 30 minutes.  We have also used MCNP (Monte Carlo N-Particle) to establish a comprehensive and flexible computer model to realistically estimate the radiation dose absorbed by a field worker.

Amerada Petroleum drilled the first producing oil well in North Dakota in 1951. When Amerada and Hess merged, it provided Hess with a strategic position in North Dakota for the shale oil boom, assisting Hess in the acquisition of almost 900,000 acres at peak.

The initial development plan for North Dakota was 3 Bakken wells per Drill Spacing Unit (DSU) covering 1280 acres of total spacing. The discovery of the Three Forks formation and the success of infill drilling and tighter spacing increased the total anticipated well count for Hess in North Dakota to over 4,000 wells.

The expected well count in North Dakota increases the long term OPEX (failures) concern. With the current failure rate approaching 0.5 failures/well/year, 2,000 failures per year would put a massive burden on resources. This paper will review the process Hess has adopted in order to manage and decrease failure rate while increasing the total well count.

Improving Paraffin Treating by Modernizing Chemical Applications: A Case Study of Pressurized Injection vs Positive Displacement Pump

This paper describes a novel technology that applies paraffin inhibitor with a pressurized injection system. The technology uses nitrogen gas to pressurize a chemical reservoir.  An electric programmable valve controls the flow of chemical out of the reservoir.  Adding an electric programmable valve to the flow line integrates chemical treatment and flush operation.

Pumping units using the pressurized chemical system have been able to increase the time between well interventions due to paraffin deposition.  

Performance of the treatment and integrated flush improve chemical delivery and improve chemical performance.

Satellite telemetry allows users to remotely monitor the chemical usage, inventory, and reservoir re-filling to add a level of confidence and dependability to the system.  The system can tie to either the pumping unit or well PLC/POC to only operate when the well is operating.

Determining the optimal equipment layout for an oil and gas facility must consider hazards resulting from a fire, explosion or toxic gas releases.  Over the years, many incidents have occurred where workers were injured or equipment was damaged by explosions, fire or toxic gas releases when equipment or occupied structures were not located properly. This paper presents “state of the art” techniques to allow facility designers to optimally locate equipment to reduce the risk of injury and equipment damage.

This paper reviews current industry “best practices” and also presents examples for the proper layout and spacing of equipment at oil and gas facilities.  The techniques presented in the paper enable the facilities designer or Engineer to quickly gather the information needed for the analysis, evaluate credible scenarios and then make the necessary judgments to properly locate equipment.  The result of using the information presented in this paper is that equipment and occupied structures are properly located and spaced to reduce operational and safety risk.    

: Paraffin is one of the major flow assurance problem in west and south Texas.  The mitigation techniques for the case of onshore paraffin deposition is different from the offshore case.  Chemical treatment is used instead of a pigging method for the onshore case.  The current reliable methods for the onshore paraffin treatment are (1) downhole chemical injection, (2) solid paraffin inhibitor pumped during hydraulic fracturing, (3) hot water or oil circulation.  The magnetic conditioning is also being 

used in some field, despite the lack in the understanding of this method.  

This paper reviews the current understanding in paraffin deposition problem (single-phase, oil-water, gas-oil), mitigation technique and its current development.

Accurate prediction of the behavior of multi-phase flow through wellhead chokes is required for modern production design and optimization of oil well performance.

This study presents the development of an empirical correlation that predicts the performance of simultaneous flow of oil, gas and water mixture through wellhead chokes. The correlation was derived on the basis of actual production data. The newly developed correlation predicts liquid flow rates as a function of flowing wellhead pressure, gas/liquid ratio and surface wellhead choke size.

The study involves a comparison between the available choke correlations based on 200 field tests from twenty wells. The correlations used in this study are those of Gilbert, Al-Attar, Ros, Baxendall, Achonge, and Secen. The Absolute average percent difference is computed for each correlation. Secen correlation has the lowest error compared to the other examined correlations. However, none of the tested correlations is found to be accurate in all ranges of wellhead pressure, gas/ liquid ratio and choke size. The validity of each of these correlations is limited to a specific operational condition for which the correlations are determined. As a result the strength of those correlations for predicting the actual flow rate is restricted.

Due to discrepancy of results obtained by the included correlations, multiple regression analysis using the statistical technique using the Doolittle method is used to create correlation that best fit the measured data. The proposed correlation is similar to the Gilbert-type empirical correlation.

The new correlation was examined against other correlations using another 110 well test data. The results are found to be statistically very good compared to those predicted by other published correlations considered in this work. 

A newer trend in gel treatments is using preformed particle gels (PPGs) to reduce fluid channels through super-high permeability streaks/fractures. This work sought to determine what factors influence the blocking efficiency of PPG on fluid channels.

A transparent model was designed to observe the compression of gel particles in fluid channels at different load pressures to study the effect of different parameters on PPG blocking efficiency.

Permeable gel pack was formed in fluid channels by gel particles and its permeability depends on particle sizes, brine concentrations, and load pressure. Gel pack is compressed and its permeability is reduced as load pressure increases. The permeability of gel pack increases with the increase of particle sizes. The blocking efficiency of particle gels on channels will reduce if we select large sized or/and strong particles.

A gel pack which has a desired permeability can be designed by selecting proper gel at reservoir pressures.

The combination of two technologies- horizontal drilling and hydraulic fracturing- made it possible to produce shale oil reservoirs economically.Although the massive stimulation treatment is the primary solution to recover efficient amount of oil from shale oil reservoirs, the recovery factors of these reservoirs are expected to be around 5-10%.The enormous remaining oil volumes stimulate our efforts to investigate the application of enhanced oil recovery methods in shale oil reservoirs. In unconventional reservoirs, cyclic gas injection using various gases could be an effective technique. Since it is a single-well process, well-to-well connectivity is not required. The hydraulic fracturing provides a large contact area for the injected gas to penetrate and diffuse into the low-permeability matrix swelling the volume of oil and increasing the near wellbore pressure which helps increasing the oil recovery in the production stage of this technique. Experimental and numerical studies by Gamadi et al, 2013 and 2014, and Tovar et al 2014, have shown that there is a great potential of increasing the recovery factor from shale oil formation. Since the hydraulic fracturing provides a large contact area for the injected gas to penetrate and diffuse into the low-permeability matrix, we investigated the performance of Cyclic Gas Injection on acid stimulated shale oil cores. The aim of the acid stimulation treatment was to improve the low-permeability matrix of the shale cores. The results showed that the acid treatment cores resulted in improving the porosity and permeability, this improvement led to better recovery factors comparing to unstimulated cores. In the conclusion, the combination of acid stimulation treatment followed by cyclic gas injection led to improving the recovery factors of the shale cores to about 50 % comparing to the unstimulated shale oil cores used in previous studies by Talal 2013 and 2014.

Oil well cementing has come a long way since the first verified use of cement in oil wells in 1903 by Union Oil Company. The years that followed have seen a remarkable amount of research and technological innovation in fluid flow mechanics, cement rheology, cement additives and cement job procedure. Given its purpose, well cementing is perhaps the most crucial stage in the development of any oil or gas well and as such proper procedure and guidelines as well as adherence to regulations are necessary to ensure success. This paper presents a summary of recommended best practices for all the stages of a cement job, from slurry design and lab testing, to job design, execution and evaluation.

This work explains how to evaluate the different perforation parameters of the production vertical oil wells by using both reservoir and perforation information. We collected the necessary data from Hungarian oil wells including reservoir description data from the MOL Company files. We also collected the perforating guns data from the Schlumberger Company. We used four perforating HSD guns with different charge and explosive load design.

We used a calculation method to determine the perforation depth, the influence of the different composite skin effect (damage skin factor, crushed zone skin factor, and the perforation skin factor), than we evaluate the flow rate of the different kind of guns. After giving the detailed figures and results, we evaluate the results of the perforation work. In conclusion, Hungarian oil wells will improved their productivity by using high shut density guns. Flow rate evaluation needs a good knowledge of rock properties, and flow properties.

Various options are available for successful underbalanced well intervention.  This paper will compare two common methods, coiled tubing and snubbing (hydraulic workover), discussing each approach’s advantages, applications, and wellbore considerations in selecting an underbalanced intervention method.  In addition, unit specifications, basic calculations and selection criteria will be addressed.

Adequate preparation & design helps assure successful hydraulic fracturing.  This paper will discuss the basic information that goes into frac design including fluid type, proppant selection, and equipment requirements.  In addition, basic calculations, quality control and additional requirements for job preparation will be discussed.