Changes are coming to oil and gas development planning that have the potential to vastly improve the game for operators, cutting down on site development time, improving well efficiency and offering cost savings across the board. By taking a modular approach to oil field development, rather than designing each facility individually, operators are becoming better able to manage their type curves, plan their long-term equipment needs and maximize the overall efficiency of their systems.
These changes are driving significant improvements in both efficiency and cost savings. Not only do modular facilities designs enable operators to plan out their entire oilfield developments in advance, maximizing overall production by limiting downtime and easing ongoing site management, but this approach also incorporates type curve planning allowing for more efficient, better organized installations. Further, modular site designs are simpler to build, cutting down on build out, well preparation and maintenance time. In terms of cost savings, modular sites enable operators to order equipment in bulk, thereby saving on upfront costs.
The key ideas behind the modular oilfield are threefold: repeatable, consistent and interchangeable. The goal is to minimize field construction by using prefabricated, pre-designed pieces of equipment that are built on assembly lines with standard options in place. All the operator has to do is order up the pieces they need and effectively plug them into their system. In theory, that's all there is to it.
These types of systems are great because they offer quick, cost effective solutions, but they can be challenging because updates and changes aren't always easy when systems are shared site-wide and designs are in the hands of a single modular manufacturer. Fortunately for operators, there are other options.
One step beyond this is fit-for-purpose modular design. By taking an operator's existing facilities and "modularizing" it, sites can be built that include both modular pieces as well as custom-designed equipment. This way the operator still owns their own equipment designs that they can take to any manufacturer for production, leaving them in control of their equipment rather than being beholden to any one modular designer. It's like buying a car off the lot versus going online to build and price a custom car.
And that brings us to adaptable modularity, which is the use of adapters to fit off-the-shelf pieces together with existing equipment. This is the best of both worlds: Lower-cost modular pieces adapted to work with more complicated, proprietary customer systems. Facilities are becoming more complicated, so we need to adapt existing pieces from established providers to work with new parts. It's about adapting standard equipment to your needs in a scalable, interchangeable, and safe way.
Why do these equipment trends matter to the industry at large? More than six decades after it was first introduced to the market, hydraulic fracturing is now a mainstay of the U.S. oil and gas industry and has emerged as a key technology in the nation's push for energy independence. We are finally in a position, thanks not only to rich product reserves in the lower 48 states but also new techniques that allow us to fully exploit these reserves, to meet all of the United States' energy needs, both today and well into the future. Hydraulic fracturing is at the heart of this opportunity. With that promise at stake, now is the time to improve on these decades-old production techniques in order to maximize their efficiency and ensure long-term cost savings for operators.
The modular oilfield is a key step in this direction.
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.
In the past decade, Hydrogen Sulfide gas has begun to appear in many Barnett Shale gas wells. As more wells are drilled and hydraulically fractured, larger populations of bacteria are introduced to the formation resulting in the current concentrations of H2S that are observed today. In addition to a lack of biocide treatments, wells are often hit by fracs from other producers in the area. As the fractures in the rock converge, new bacteria are introduced that were at first only present in a neighboring well. This idea of fracture convergence prevents treating the problem at the source, as operators cannot control well contamination caused by other companies. The rapid rate at which bacteria are growing and spreading demonstrates a clear problem. To prevent H2S concentrations from further increasing, it is critical that a sustainable field treatment program is developed and implemented.
The completed study involved an analysis of 96 wells operating under the biocide treatment method, continuous wet-gas injection method, and continuous dry-gas injection method. The study took into account gas flow rate, H2S concentration, produced water rate, and chemical usage rates. The results yielded a final $/MMCF value for each well under its respective treatment method.
The results of the study showed first that specific treatment options apply to specific circumstances. For example, the iron sponge media proved to be the most effective long term mitigation option while the scavenger chemical flow loop design provided the adequate retention time required for lower concentrations of H2S. Furthermore, there was no clear evidence that disproved the effectiveness of conventional biocide treatments. According to test results conducted before and after separation, dry gas chemical treatment proved to be more efficient than wet gas treatment.
Because H2S is not native to the Barnett Shale, many operators are only recently discovering problem wells. This report provides in detail, the pros and cons of a variety of different treatment options accompanied with field-study results. Other operators can use this information to safely develop and improve their H2S treatment programs.
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.
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.
The Mississippian formation in Oklahoma and Kansas significantly contributes to oil and gas production in the region. This formation is a lime deposition with substantial secondary porosity that can be created by fractures and vugs. These alterations can change the capacity of the formation to produce fluids. Characterization of the primary porosity condition and the altered condition of the reservoir are not possible using conventional openhole logging practices.
Nuclear magnetic resonance (NMR) logs were added to logging programs to attempt to resolve these issues. This device only measures fluid, and the sum of all fluids present results in a direct measurement of the total and effective porosity. The evaluation of relaxation from the NMR measurement and calculation of permeability provides an estimate of permeability that is consistent in conventional reservoirs.
Full cores were taken in Mississippian wells, and a conventional core analysis of porosity and permeability was performed in 1-ft increments. This study compares the results of porosity and permeability from NMR to these same values, as determined by laboratory work on the cores. Some of the sections are unaltered; other portions have significant secondary alteration.
In all portions of the reservoir considered, permeability thickness (Kh) and porosity from both core and NMR are comparable. Operators attempting to evaluate this reservoir using openhole logging techniques now have a powerful and accurate technique to determine these reservoir properties before incurring expenses associated with completion.
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.
Hayatdavoudi, A. (University of Louisiana at Lafayette) | Boamah, M. A (University of Louisiana at Lafayette) | Tavnaei, A. (University of Louisiana at Lafayette) | Sawant, K. G. (University of Louisiana at Lafayette) | Boukadi, F. (University of Louisiana at Lafayette)
It has been almost 70 years since the first hydraulic fracturing job was carried out. Since then, hydraulic fracturing has made it possible to produce oil and clean burning natural gas from shale where conventional technologies are ineffective. However, in fracking the shale, the mechanism of increased gas production after the
To shed light on this issue we have studied and experimented with Pierre shale in detail. In our experimental work we suspended approximately 15 grams of shale cubic samples in deionized water. We have measured the changes in pH, Eh, (Redox potential), and Temperature and simultaneously have recorded the process of gas bubble flow under microscope, using a video system. We plotted our 1024 data points taken every three seconds. We used the Fourier Transform of the data to construct the Power Spectrum for extracting the hidden information in the data in relation to the release of the
The results of time series analysis in frequency domain reveals the following information: (1) depending on the type of shale, it takes a certain amount of time for water molecules to saturate/activate the shale capillaries. This is analogous to the
The practical application of our paper is (1) we propose a simple and cost effective methodology for determining the post frac optimal shut-in time and (2) once this optimal shut-in time is implemented the industry may benefit from realizing higher gas production from their prospects.
Production of sour crude oil releases hydrogen sulfide (H2S) into production tubing and surface equipment, causing corrosion, flow assurance issues, i.e., iron sulfide deposition, safety, and environmental concerns for the producer. As a result, increased costs related to metallurgical upgrades, gas sweetening equipment (i.e., towers), increased manpower costs for monitoring, and liability from the potential release of H2S can become significant parts of the total operation cost. These issues can be alleviated if the H2S is reliably removed downhole and prevented from reaching the surface.
Conventional hydrogen H2S scavengers such as triazines or glyoxal are commonly applied by direct injection topside to mitigate H2S in oil and gas production facilities. However, when applied in direct-injection applications, these scavengers exhibit slow kinetics that reduce their effectiveness in short residence-time systems, resulting in a much greater amount required than theoretical efficiency would predict. Neither triazines nor glyoxal are suitable for downhole application because of their low thermal stability and, in the case of triazine, its high scaling tendency.
To achieve reliable and cost-effective removal of H2S downhole, the development of a new scavenger and a new delivery system was required. As a result, a new non-triazine, organic acid metal complex-based H2S scavenger (OAC) with high-temperature stability, fast kinetics and quantitative H2S removal was developed. The new delivery equipment comprises an injection skid, H2S monitoring equipment and an automated chemical dosing system to assure delivery of the precise dosage required to remove H2S downhole.
Field test results for the new OAC scavenger and delivery system will be presented for mixed production applications, demonstrating the ability of this approach to reliably remove H2S downhole.
A new technology has been developed to transport substances downhole for various oilfield applications. This introduces a new method of delivering solutions in a timely manner with a long-lasting efficacy, with no extra steps or additional mechanical tools. A group of naturally derived copolymers, the use of which is new in the oilfield, can be employed as the delivery vehicle for different species in various forms including beads, capsules, sheets, or strips, as suited for different uses. This technique can be employed for treating one or more adverse downhole conditions, such as, scaling, corrosion, or organic deposits for a prolonged period. This technique can also be used for transporting a chemical agent, such as, a tracer, a pH or a surface modifier, a scavenger, or a viscosity enhancing or reducing agent, either as solid or in their liquid form. This paper will present one of the applications, namely treatment of common inorganic scales downhole, involving this innovative approach. In this particular case, the treatment agent is delivered with the stimulation fluid and is placed with proppant along the fracture length. This approach not only treats the scaling issues efficiently for longer period of time compared to any current products available, but also causes no significant damage to the proppant-pack conductivity. Additionally, it is environmentally-safe and cost-effective. This paper will describe the laboratory testing involved in developing this new technology in detail. The paper will also discuss our recent field validation studies for pumping in the Gulf of Mexico.