The performance of downhole gas separators is simulated in software.  Different production rates, different sizes of separators, different SPM and different gas bubble rise velocities are simulated to show the performance of different separators and different well conditions.  This simulation software is a great aid in educating personnel in the operation, performance, selection and proper design of gas separators.  Knowledge and use of this software will help operators increase pump fillage and total production and also reduce operating expenses.

Sucker rod pin and coupling failures continue to plague the oil and gas industry and escalate lifting costs.  The rod connection is solidly designed and is up to the task of staying together if it is properly treated in the field.  Clearly, all paths to the root causes of the premature connection failures lead to field techniques, practices and to unrecognized and uncontrollable variances.  The useful life of a sucker rod is clearly dependent in part, to how it is handled in the field.

This paper will present datasets gathered from the recently developed CDDs (Circumferential Displacement Device) to illustrate "the life" of the sucker rod connection from its initial first make up to point where permanent deformation might call for the retirement of the rod and or coupling.

Hydraulic tubing anchors have been around for over 30 years, however the technology has greatly improved in recent years. To better understand the dynamics of hydraulic anchors, a test rig was constructed to approximate downhole conditions in terms of depth and holding capacity. The test assembly allows for controlling the perceived depth by way of pressurizing the tubing, or internal bore of the hydraulic anchor.  Varying the pressure in the "tubing" simulates the pressures seen at any depth. The holding capacity of the anchor is tested by a hydraulic jack placed under the anchor. The jack, having know bore can easily correlate PSI to lifting force placed on the eh anchor. Numerous tests were conducted at varying depths to find the lifting force required to dislodge, or cause the anchor to slip. Anchor test data as well as analysis of the interface between the anchor and casing will be presented.

The definition of as Gas Locked Pump is both traveling and standing valves remain closed during the entire stroke.  Gas Lock of a sucker rod pump occurs if the tubing pressure on top of the plunger is always greater than the pressure inside the pump chamber and if the pump chamber pressure is always greater than he wellbore pressure on the outside at the pump intake.  The traveling and standing valve open if pressure below the valve is greater than the pressure above the valve.

High compression pumps, specialty pumps, tagging, and slippage through pump clearances cause the chamber into the tubing.  Operators stating "my pump is gas locked" usually have pumped too much gas into the tubing, resulting in unloading all tubing fluids.  Pump action has ceased and the classic dynamometer card "Gas Lock" shape of a gas locked pump is not observed.

The production of the shale oil well at start up can produce high fluid rates with a high energy causing it flow naturally. After this stage, a high rate artificial lift systems such as ESP or Gas lift is required. But because of the rapid depletion of the stimulated zone during the first year (between 60 – 80% in Eagle Ford), the most flexible form of artificial lift available is used, the beam pumping.

Because the pump depth could reach between 4000 up to 12000 ft., the beam pumping system is limited in flow rate.  A big surface pumping unit and high strength rod are necessary. Other complex challenges to overcome are the combination of crooked or highly deviated well bore, high GOR, propant or sand flow back and the presence of H2S. Small tubing completions in shale wells, with 2 3/8” tubing installations, pushes the system to provide high fluid velocity with effective solids transportation in low rates and more inexpensive equipment but with sucker rod diameter restriction to 7/8” slimhole couplings.

Optimizing artficial lift equipment selection , sizing and design with ensure longevity of the equipment and continued production. A premiun sucker rod connection has a design that allows the use of 7/8" and 3/4" strings tapers with KD material to work in corrosive environments with regular size pumping units and lighter strings with guide when neccessary in wells where 1" and high stregth rods should be the conventional alternative.

This paper explains the experiences of more the 70 strings installed and the benefits achieved for a major operator working in the Eagle Ford formation.

Rod Pumping New Drills--sands issues then gas issues-a discussion of rod pump designs for these wells.  As a new wells are brought on many times a great deal of sand is coming back through the rod pump. The pump may also experience gas interference then or later on as the fluid level has been down down.  This paper will discuss many different rod pump designs and why they would be an effective design, a possible design, or a poor design for sand and gas producing new drills.

If no pump action, a recommended practice is to shoot a fluid level down the casing annulus and also shoot a fluid level down the tubing.   Distance down the tubing is determined by using the average acoustic velocity obtained from the casing shot.  DO NOT use the tubing average joint length to interpret the down tubing fluid level, because inside the tubing rod couplings are spaced at the length of the sucker rods.

Analysis of the acquired data can determine such things as: If there is a hole in the tubing.  Additional tubing back-pressure maybe required if tubing liquid was unloaded by significant amount of gas produced up the tubing.  Tubing pressure buildup measurement determines the amount of gas flowing up the tubing, tubing percent liquid, and the effectiveness of the dowhole gas separation. Difficult to interpret tubing shots may indicate that the well has “paraffined-up”.  Tubing shots acquired at uniform time intervals can show ineffective pump operation, where “pumping up” the tubing occurs too slowly. Down tubing fluid levels are effective tools when troubleshooting shooting a shut-in sucker rod pumped well suspected of having no pump action.

Available sucker-rod strong design models calculate rod taper lengths that ensure proper operation without premature fatigue failures. Their common design problems are (a) defining the principle of taper length determination, and (b) calculating the true mechanical stresses along the string. The universally accepted principle of taper length calculations is to province the same level of safety against fatigue failure in each taper section. Mechanical loads and stresses, not he other hand, are found form highly approximate calculations in most of the design procedures. These loads, therefore, can greatly deviate from the true mechanical loads that would be measured in the rod string run in the well. The paper discusses the development of a novel procedure that estimates rods loads from the predictive solution of the damped wave equation when designing the rod string. Since loads calculated that way very accurately imitate actual loads the most important limitation of previous rod string design procedures is eliminated. Strings designed using the proposed model, therefore, have a much enhanced safety against fatigue failures as compared to previous designs.

In hydraulic fracturing operations, a large fleet of equipment is required to blend and pump fluid down a wellbore to fracture a formation. High horsepower diesel pumps create the force needed to induce fractures within the wellbore, and in the process, can consume 6,000-8,000 gallons of diesel fuel each day.

In an effort to reduce this consumption, Baker Hughes recently introduced the Rhino biofuel hydraulic fracturing pump which allows for up to 65% replacement if its diesel consumption with natural gas during pumping operations. Biofuel systems present several significant advantages such as no loss of horsepower, improved emissions, reduced diesel consumption, and the utilization of natural gas as a fuel without utilizing a spark-ignited natural gas engine.

With more stringent emission requirements being set forth by the Environmental Protection Agency, it is beneficial to have the ability to reduce operating costs and engine emissions by using cheaper, cleaner natural gas.

As of January 5, 2014, all planned maintenance start-up and shutdown (SMSS) must be accounted for and permitted. TCEQ has also had an effective policy change in what is regarded as MSS and may now consider events related to MSS as Alternative Operating Scenarios (AOS). This paper explores the difference in planned vs. unplanned MSS, when it needs to be reported, when and where it must be reported to, and how to properly plan for complying with the regulatory requirements regarding MSS and associated concerns.

When installed in the liquid leg of the separator, Vortex Tools spin and entrain harmful hydrocarbon vapors from the gas, thereby increasing the oil recovery. By doing so, operators remaining compliance with EPA air quality emissions while recovering additional oil condensate and natural gas liquid values (NGLs). Increased oil recovery, reducing BS&W and cheaper gas are the results of this patented process.

Tested in E Texas wells at 103-degree F ambient daytime temperatures, all production tanks were in air compliance with Vortex (especially important as the number of wells-per-pad has increased while air quality standards remain the same). These patented Vortex tools use no additional energy source, have no additional carbon footprint, and no moving parts/maintenance.

Vortex Tools presented at the 2012 SWPSC on its application for recovering 1 time more natural has liquids than pigging.

A new federal air quality rule governing midstream and upstream activity is in effect.  The rule, also known by its more formal citation 40 CFR Part 60 Subpart OOOO, or ‘New Source Performance Standards (NSPS) Subpart Quad O’ contains new regulations and revisions to existing statutes. This rule will have a major impact on how the Oil and Gas industry has been operating regarding waste gas emissions.  Reverberations will be felt across the industry by these more stringent rules governing upstream exploration and production segment as well as the midstream segment. The rule addresses fracking, compressors and production emissions but the largest source of waste emissions will be generated by storage vessels.  According to World Oil’s estimate of  producing wells, based on surveys of state agencies and company sources, indicates there are over 536,000 oil producing wells and 485,000 gas producing  wells. A very conservative estimate would be about approximately 650,000 crude oil, produced water and condensate storage tanks in the United States and is increasing. Any new Oil and Gas storage tank will be regulated by NSPS Quad O if emissions of VOC’s are more than 6 tons per year. According to the regulation they must reduce emission by 95% through recovery or combustion to be in compliance. Change is in the air.

The Chemistry of Chlorine Dioxide is finding application in oilfield water treatment. The team at Aegis has adapted for the efficient delivery of C102 in both Frac water treatment as well as produced and flow-back water.

Chlorine Dioxide has a positive environmental profile and has proven to benefit the health and profitability of Oilfield systems.

The application of Aegis' Technology working closely with customers has allowed for the elimination of other traditional chemical treatments in favor of the rapid results delivered by Chlorine Dioxide.

Are the new flaring regulations creating more headaches for you?  Are your sites ready for the April 2014 compliance date?  Is the definition of a flare, enclosed flare, combustor, and thermal oxidizer creating confusion and heartburn?  Join us in a healthy discussion to help eliminate the troubles…  We’ll discuss what the differences are between flares, engineered flares, and enclosed combustors.  We’ll also discuss criteria used to size and select an enclosed combustor, regulatory drivers, emission figures, data logging, and how all this impacts your site.  Additionally, we will present solutions for the common vapor destruction requirements as well as the ability to design custom solutions for unique site issues that can offer cost benefits and ease of site operation to you!  Finally, we’ll touch on new “Greenhouse Gas” rules coming out in January 2015 and the impact on drilling sites as it relates to flares and enclosed combustors!

Alternatives need to be considered for delivering chemical treatments to rod pump wells.  This paper reviews the problems with the current treating methods and proposes an alternative that mitigates the problems wit the current procedures.  This alternative uses a circulating treating skid to displace chemical treatments through a filtering system.  Operational criteria for the CT skid are discussed as well as its cost effectiveness compared with current practices.

Long term scale inhibition and economic enhancement is a desired outcome for oil and gas operators. The completion phase of a well involves hydraulic fracturing, which involves the introduction of a mixture of water and specially engineered chemicals pumped at high pressures and rates to achieve a fracture into a low permeable formation. Due to these mix waters, pressure, fluctuations, and temperature variations form the fracturing operation, liquid scale inhibition chemicals are typically pumped 'on the fly' throughout the fracturing treatment. Typically, these chemicals deplete within months after the fracturing operation and the need for continuous intervention from a chemical service company is then required to inhibit any scale potential as the well produces. This study evaluates a wolfberry trend field and compares conventional liquid scale inhibitors versus solid inhibitors over a selection of over 300 wells. This study demonstrates the effectiveness of scale inhibition, longevity, and the economic impact.

The use of computer-generated software to predict radio frequency (RF) path studies has been around for several years. Combined with the latest GPS and Google map data, you can determine how well your network will work, its RF path link reliability, link budgets, Fresnel zones, multi-path and if you mat need to invest in different towers, use more repeater or add additional technologies to try to cover the area you need for data communications. By examining the guidelines and some fairly simple explanations of how to get the correct information, attendees can discover the true benefits of this software. Topics include a look into radio signal path loss -- a particularly important element in the design of any radio communications system or wireless system, predicting the signal path loss, free space path loss basics, link budget antenna gain and the effect of multipath propagation to achieve maximum throughput and reliability.

Organizations with geographically dispersed assets in the field, such as those in the oil and gas industry, would typically select one technology, one source, or one vendor to collect, retrieve and report critical data. Therefore, building large, elaborate wireless communications networks with a single technology was a way a company might demonstrate its decision-makers to consider better manageability, expandability, cost and speed. By integrating various types of telemetry technologies together, it can offer significant benefits that are easily and cost-effectively incorporated into one cohesive data communications network.

Collecting data from multiple locations and delivering it over a widespread area can create challenges that no one technology can overcome alone. Hybrid communications networks can incorporate carious technologies and address key factors such as data security, network speeds, infrastructure costs and on-going costs to meet your specific network objectives.

A field in OK previously used incompatible water for waterflooding with an inadequate inhibition program and the flood was subsequently shut down due to barium sulfae scale.  The waterflood was reactivated years later using the same water but with a much more effective treating program with has been successful fore several years.  This paper documents the program.

It has become increasingly attractive and necessary to reuse treated produced water for frac fluids, especially in remote locations or limited water sources regions to minimize freshwater usage. Eletrocoagulation (EC), a traditional water remediation technology, was recently introduced to oilfield application. However, the complicated components in produced water are challenging for traditional EC systems.

A new EC apparatus has exhibited cost-efficient remediation of produced water, especially in the removal of iron and suspended solids that have restricted concentration for making frac fluids. The unique EC system has demonstrated fast reduction in iron from over 900 ppm to less than 5 ppm from high-concentration oil contained water, and efficient removal of hydrogen sulfides (H2S), heavy metals, bacteria, and other contaminants. The system has been successfully used for treating produced water for numerous operators in the Permian Basin, reducing operating costs more than 20% while reducing freshwater demand and trucking over 90%.

Water management is one of the largest expenses associated with the production of oil and gas (O&G) resources. Water recycling and reuse can save time, costs, and resources for exploration and production (E&P) companies resulting in enhanced operating efficiencies and improved bottom line results.

Electrocoagulaon (EC) is a technology based on proven scientific principles of electro-chemistry and successfully used in the water treatment industry for many years.  Recently, EC has grown rapidly as an effective and economical method for treating water in the O&G industry. The use of EC is a proven method for treating produced and flowback water or reuse in production activities or subsequent frac jobs.  Savings are generated from reducing costs associated with fresh water sales, water transport, and disposal. Compared to traditional treatments utilized to remove residual oil and suspended solids, EC delivers lower operating costs using less labor and smaller footprint.

COG Resources has drilled and completed over 1500 commingled YESO wells in Southeast New Mexico.  Over the past 6 years, COG Resources and Catalyst have developed strategies to address the producing conditions and known fluid incompatibility.  These strategies can help other operators in the area, in addition to operators producing in multiple horizons where fluid compatibility is an issue.

Cementing has been an important part of wellbore isolation and stability for decades.  Cementing, though, if not implemented properly can also be costly, resulting in wrong densities, incorrect displacement, flowback, micro annulus, etc. However, these issues can be avoided with experienced quality control practices. This paper outlines a practical approach to cementing quality control to ensure that the operator has the best opportunity to achieve successful cement mixing and displacement. Case histories are presented to demonstrate the importance of these quality control practices.

Since the late 1940's, proppants have been the primary construction material for a conductive hydraulic fracture.  However, it was not until the late 1970's that critical properties were indentified and performance examined under guidance from the American Petroleum Institute (API). By the early 1980s SPI proppant testing recommended practices (RP56, 58, & 60) to be applied at the website were scribed and introduced. Yet, employment of these American standard practices at the wellsite became cursory as the rig count collapsed and time passed.  This subsequently left the industry with inconsistent data, lack of accountability, poor record keeping and little information for assessment of delivered proppant. The three API standards have since transitioned to one, RP 19C. This paper illustrates correct application of the standard in a four step approach (test, reference, track, review) to consistently reconciled bargained and delivered proppant.

High concentrations of total dissolved solids (TDS) are typically problematic in fracture fluid development due to interactions with the buffers and crosslinkers used for waters of higher quality. High hardness and high temperature usually cause loss of viscosity in the fluid; however, proper frac fluid design can successfully keep viscosity and pump the job. This paper will discuss the successful design of a borate crosslink frac fluid design that reuse produced water treated with electrocoagulation (EC). The water in this particular case history had high concentrations of calcium and magnesium with a calculated TDS greater than 250,000 ppm. In the field, oil and iron quantity were changing, although the hardness and TDS remained high. The frac fluid design was able to accommodate the high hardness with little variability in formulation throughout the frac. Different buffers as well as our most concentrated borate crosslinker were able to maintain stability.