Gathering Line Research Articles

Testing the functionality of OLGA software for determining optimal oil transport modes to prevent solid particle deposition

Background: During operation, all mechanical impurities entering the collector through the flow lines settle at the bottom due to a decrease in flow velocity. This leads to a reduction in the capacity of the pipeline network, increased pressure, and premature equipment wear. To address this issue it is essential to understand the dynamics and intensity of sludge formation at the bottom of the pipeline. Aim: Evaluate the functionality and efficiency of the dynamic multiphase flow simulator in addressing challenges related to the transport of borehole fluid containing solid particles. Materials and methods: To build a mathematical simulation of multiphase flow with solid particles using OLGA specialised software, we selected one of the oil gathering lines in field N, with a diameter of 159х10 mm and a length of 1600 m, as the study object. This oil gathering line collects production from 16 wells. The OLGA simulator was used to model the process and measure flow parameters with different particle diameters, predicting the dynamics of variables such as time-varying flow velocities, fluid composition, temperatures, and particulate deposition. For a flow with a particle diameter of 104 µm, active precipitation occurs at flow rates between 200 and 300 m³/day. At flow rates of 400 m³/day and above, the velocity is sufficient to carry the particles without significant accumulation in the pipeline. Results: The software enabled the calculation of the dynamic system for different solid particle diameters in multiphase flow, addressing the challenge of evaluating the dynamics of solid phase accumulation in the pipeline and determining the fluid flow velocity required to prevent sludge formation. The software is suitable for implementing simulation modelling to develop technical solutions that minimise the risks of solid particle deposition in oil gathering pipelines during the operation of on-shore infrastructure facilities. Conclusion: The software enabled the calculation of the dynamic system for different solid particle diameters in multiphase flow, addressing the challenge of evaluating the dynamics of solid phase accumulation in the pipeline and determining the fluid flow velocity required to prevent sludge formation. The software is suitable for implementing simulation modelling to develop technical solutions that minimise the risks of solid particle deposition in oil gathering pipelines during the operation of on-shore infrastructure facilities.

Study on the Destruction Law and Main Controlling Factors of Corrosion Product Film in H2S-CO2 Coexistence System

Abstract The failure law and main controlling factors of corrosion product film in this corrosion environment were studied according to the characteristics of H2S-CO2 coexistence in a gas field pipeline, so as to provide guidance for corrosion prevention and control of gas field pipeline. Sediment effects of sand particles in the pipeline on corrosion, the influence of flow rate, dissolved oxygen and sediment on corrosion products were analyzed by conducting corrosion experiments at 0.5m/s, 1m/s and 2m/s, corrosion experiments without oxygen and aerobic conditions. The destruction law of corrosion product film in pipeline and the main controlling factors of corrosion product film in single well pipeline and gathering and transportation line were determined. The results show that high flow rate will cause local damage of corrosion product film and promote pitting corrosion, dissolved oxygen will destroy the integrity of corrosion product film, and sediment is one of the factors causing local corrosion and perforation of pipeline inner wall. The corrosion product film structure of the gas field pipeline will be destroyed and pitting corrosion under the condition of high flow rate, oxygen and sand deposition. Meanwhile, the main control factor affecting the corrosion product film destruction of the gas field single well pipeline is dissolved oxygen, and the main control factor affecting the corrosion product film destruction of the gas field gathering and transportation main line is sediment.

Using controlled subsurface releases to investigate the effect of leak variation on above-ground natural gas detection

Pipelines transport natural gas (NG) in all stages between production and the end user. The NG composition, pipeline depth, and pressure vary significantly between extraction and consumption. As methane (CH4), the primary component of NG is both explosive and a potent greenhouse gas, NG leaks from underground pipelines pose both a safety and environmental threat. Leaks are typically found when an observer detects a CH4 enhancement as they pass through the downwind above-ground NG plume. The likelihood of detecting a plume depends, in part, on the size of the plume, which is contingent on both environmental conditions and intrinsic characteristics of the leak. To investigate the effects of leak characteristics, this study uses controlled NG release experiments to observe how the above-ground plume width changes with changes in the gas composition of the NG, leak rate, and depth of the subsurface emission. Results show that plume width generally decreases when heavier hydrocarbons are present, the leak rate is reduced, and as leak depth decreases from 0.9 to 0.6 m. The study illustrates that heavy gas leaks from flowlines and gathering lines could currently be more challenging to detect than leaks from distribution pipelines as the plume is trapped close to the ground. Further, this study shows that leaks from pipelines laid in covers meeting minimum depth requirements of 0.9 m could be easier to detect compared to those buried shallower. Overall, this study illustrates that leak survey protocols for flowlines and gathering lines should be different from distribution pipelines and tailored to the compositions of the transported NG to report emissions accurately. The study aims to improve the understanding of flowline/gathering line leaks to prevent fatal accidents, such as the 2017 explosion from a gathering line in Firestone, Colorado, that resulted in two fatalities and one injury.

Study on the Segmental Pigging Process for the Wet Gas Gathering and Transportation Pipelines of the Puguang Gas Field

Abstract The gathering and transportation pipeline known as Line 1 of Puguang Gas Field has the characteristics of wet gathering and transportation containing high sulfur content, large drops, and liquid loading in low-lying areas. In the process of one pigging operation on the site, the surge volume provided by the no. 1 separator in the master gas gathering station was not effectively utilized and the time intervals for the neighboring pipeline sections were too long. In this paper, we designed several pigging proposals. OLGA was applied to analyze the operating parameter changes for the gathering and transportation pipeline Line 1, which finally determined a reasonable pigging sequence. We designed and selected the “optimal pigging proposal”, which the time duration for the pigging operation of the seven pipeline sections was decreased to 16.91 h. Guided by the “optimal pigging proposal”, the downstream pipeline sections will be challenged by the risks of ice blockage. The ground eddy device was improved in the article, for the purpose of draining liquid loadings in low-lying areas in the Puguang Gas Field and controlling the slug flow. In addition, the application effects of the device were analyzed.

Study on Pigging Process Analyses and Control Methods for Moisture Gathering Lines: Study in Puguang Gas Field, China

AbstractThe moisture gathering line of the Puguang Gas Field in China renders it prone to accumulating liquid at certain points due to topographic differences. Under operational conditions of piggi...

Water Demand Spurs Permian Infrastructure Investment

The production growth in the Permian Basin has created a new dilemma for operators looking for cost efficiency. In September Bloomberg predicted that Permian production could rise from its present level of 2.4 million BOPD to 10 million BOPD, a rate that could produce up to 50 million B/D of flowback water. With the WTI price at around $57/bbl in early December, disposal of that flowback water can be expensive. Bloomberg estimated the cost of the service is between $1.50 to $2.50/bbl. While this predicted spike in water volume may be an issue for operators, it is an opportunity for oilfield water management companies working in the region. With demand for their services going up, these companies have already begun acquiring pipeline infrastructure, saltwater disposal (SWD) wells, and facilities. Multi-Basin Strategy With water management becoming a critical issue for operators in the Permian, midstream companies have been aggressive with mergers and acquisitions in their efforts to bolster their positions. H2O Midstream’s acquisition of Encana’s produced-water-gathering system last June gave it control of more than 100 miles of interconnected pipeline and five SWD wells with a total permitted disposal capacity of 80,000 BWPD. In September 2017, RRIG Water Solutions announced the acquisition of a 475-mile pipeline from Oilfield Water Logistics. Located in the eastern part of the Delaware Basin, the pipeline has the potential to move more than 2.3 million B/D of fresh water. WaterBridge Resources is another company that has been active in the Permian region. Since its founding in 2015, the midstream development company has focused on acquiring and operating flowback and produced water infrastructure for various oil and gas producers, including water sourcing, gathering, reuse, pipeline infrastructure, and disposal infrastructure. In August 2017, WaterBridge acquired EnWater Solutions, a company whose current assets include more than 100 miles of gathering line and nearly 150,000 B/D of permitted disposal capacity. WaterBridge plans to extend EnWater’s existing gathering business into a full-cycle, closed-loop water sys-tem, and by the end of 2018 the company expects to have more than 300,000 B/D of disposal capacity and 200 miles of interconnected gathering pipe. “The assets we acquired from EnWater are located in the southern Delaware, and the EnWater team’s expertise encompasses the entire Permian region from the Delaware to the Midland, so that was a regional platform with an existing management team that are certain areas across the US where the water/oil ratio is much greater. The Eagle Ford is fairly dry, the SCOOP/STACK is fairly wet, and the Permian’s fairly wet. The water/oil ratios are what we chase because, at the end of the day, our business is a volumetric business. The greater the volumes of water to be handled, the better our profitability is.”

Electrical stimulation characteristics of denervated orbicularis oculi muscle.

This research is to study the electrical stimulation characteristics of orbicularis oculi muscle and the characteristics of the mechanical contraction. We observed the stimulus current diffusion regularity and its relationship with mechanical contraction in the orbicularis oculi muscle using an electrode gathering line. Under different stimulus intensities of 2 or 4 mA, the closer the recording electrodes were to the stimulating electrode, the larger was the amplitude. When the recording electrode and stimulating electrode distance increased, the amplitude declined linearly with decreasing function. In addition, current conduction across the muscle fiber was studied. Under different stimulus intensities of 2 or 4 mA, it was found that the closer the recording electrodes were to the stimulating electrode, the larger was the amplitude. When the recording electrode and stimulating electrode distance increased, the amplitude declined linearly with decreasing function. The transverse current reached a maximum 4 mA range, and increasing the current intensity did not increase the propagation range. Under different stimulation intensities, the larger the stimulus intensity, the greater is the potential change and the faster is the attenuation. Longitudinal current, even in the range of 6 mm, can still record electrical activity. While a transverse current diffuser has a maximum range of 4 mm, increasing the current intensity does not increase the propagation range.

Assessment of policies to reduce core forest fragmentation from Marcellus shale development in Pennsylvania

Marcellus Shale development is occurring rapidly and relatively unconstrained across Pennsylvania (PA). Through 2013, over 7400 unconventional wells had been drilled in the Commonwealth. Well pads, access roads, and gathering lines fragment forestland resulting in irreversible alterations to the forest ecosystem. Changes in forest quantity, composition, and structural pattern can result in increased predation, brood parasitism, altered light, wind, and noise intensity, and spread of invasive species. These fragmentation effects pose a risk to PA's rich biodiversity. This study projects the structure of future alternative pathways for Marcellus shale development and quantifies the potential ecological impact of future drilling using a core forest region of Bradford County, PA. Modeling presented here suggests that future development could cause the level of fragmentation in the study area to more than double throughout the lifetime of gas development. Specifically, gathering lines are responsible for approximately 94% of the incremental fragmentation in the core forest study region. However, by requiring gathering lines to follow pre-existing road routes in forested regions, shale resources can be exploited to their full potential, while essentially preventing any further fragmentation from occurring across the core forested landscape of Bradford County. In the study region, assuming an estimated ultimate recovery (EUR) of 1–3 billion cubic feet (Bcf) per well, this policy could be implemented for a minimal incremental economic investment of approximately $0.005–$0.02 per Mcf of natural gas produced over the modeled traditional gathering line development.

Separating equipment for protecting field booster compressor stations

Possible alternatives of locating a gas separating unit in layouts of plants for preparing gas for transporting and for field booster compressor stations (BCS) are examined. Designs of a gas cleaning unit of the first separation stage with a built-in lock interceptor based on vertical apparatuses are presented. The dynamics of development of separating equipment for protecting BCS is discussed. The problem of ambiguities in current normative-technical documents relating to technical specifications of gas preparing equipment before the BCS is identified. Any field gas preparing plant is provided with a separating unit that ensures the desired degree of gas cleaning from liquid and solid (mechanical) impurities and protects the next equipment. Usually, the products recovered from the reservoir include: • liquid (water, methanol, condensate, etc.) and mechanical impurities (in varying degrees in various objects); • salts dissolved in stratal water; and • liquid locks whose volume depends on the diameter and length of the gathering line and the ground relief. Ingress of liquid locks into field objects is common for both gas and gas condensate deposits. Note that the gas parameters (pressure, throughput, temperature, liquid content, etc.) before the input separation units vary considerably with time. In general, at booster compressor stations (BCS), an additional separating unit is not provided past complex gas preparation plants (CGPP): the technology and equipment of the plants ensure cleaning of the gas. An exception may be drying with a solid sorbent, in which case a filter may have to be installed after the adsorber. When a BCS is constructed and installed before a CGPP, the gas pumping unit (GPU) needs to be protected from liquid and mechanical impurities. The protective unit may be of two versions.

The Summary of the Scale and the Methods to Inhibit and Remove Scale Formation in the Oil Well and the Gathering Line

The Summary of the Scale and the Methods to Inhibit and Remove Scale Formation in the Oil Well and the Gathering Line

The Summary of the Scale and the Methods to Inhibit and Remove Scale Formation in the Oil Well and the Gathering Line

The Summary of the Scale and the Methods to Inhibit and Remove Scale Formation in the Oil Well and the Gathering Line

A new balancer of chapped wing on chromosome 3 and a gathering line with double balancers of chapped wing (L) and Cy in Drosophila melanogaster.

The balancers of Drosophila melanogaster are widely used in genetic research. By analyzing the phenotype of offspring from hybridization of chapped wing (L) mating with OR, 982p and e, respectively, we mapped the chapped wing mutation on chromosome 3 for the first time and demonstrated the chapped wing mutation as a new balancer of D. melanogaster with dominant wing nicking phenotype. Finally, we bred a novel gathering line with double balancers of L and Cy in D. melanogaster. The mutant L provided a legible dominant marker for the balancer of chromosome 3, and the cultivation of double balancers chapped-curly wing enriches the balancer stock, which is often used in mapping and screening.

Anisotropic Mean Traveltime Curves: A Method to Estimate Anisotropic Parameters from 2D Transmission Tomographic Data

We present the mathematical deduction and properties of the mean traveltime curves for homogeneous elliptical anisotropic media. These curves generalize their isotropic counterparts which have been introduced in the past as a simple data quality analysis technique at the pre-inversion stage for 2D transmission experiments, allowing the inference of prior velocity models to gain stability at the tomographic inversion. Also, the anisotropy parameters (maximum velocity, anisotropic direction and ratio) are shown to affect the shape of these curves. The degree of asymmetry of the anisotropic mean traveltime curves (displacement of the mean time and standard deviation minima from the middle of the gathering line) is related to the direction of anisotropy which can then be visually estimated. Least squares’ fitting of the anisotropic theoretical models to their experimental counterparts is an effective method to estimate at the pre-inversion stage a macroscopic elliptical anisotropic velocity model, valid at the scale of the experiment, and able to match the experimental mean traveltime distribution.

Spill Response Strategies for Rivers in a Remote Deltaic Environment

ABSTRACT A development project in Alaska is in progress that will connect a remote producing oil field in the Colville River delta to the North Slope gathering line system and the Trans-Alaska Pipeline. The delta has a complex distributary channel system and a short (3-month) open-water season. During winter months the region is frozen and access is not a constraint for spill response operations. By contrast in the open-water season, east-west access between sites is made difficult by the north-south trending channel system and by the shallow water depths in many of the channels during non-flood stages. The generation of a summer spill response strategy for this production project initially identified the potential sources from which oil could enter this delta system and then upon the likely pathways for the spreading of spilled oil during the open-water season. A series of individual response strategies associated with each scenario was developed. The objectives of the summer response strategies are either to (1) minimize the spread of spilled oil downstream and towards the Arctic Ocean, or (2) protect sensitive habitats, such as tapped lakes that connect to the delta channels. Effective spill response actions in this remote environment are possible by adopting strategies based upon pre-deployed or pre-staged equipment. With this concept, seasonal controls for containing the spread of oil would be in place at a number of locations, and, for other sites, the initial response would require only the deployment of personnel to effect control of the spilled oil, as equipment would be already located and ready for on-site deployment.

CO 2 Transport: A new application of the assignment problem

The possibility exists that Ohio River Valley coal-burning power plant stack gases rich in CO 2 can be profitably disposed of by transportation via existing reversed flow natural gas trunklines to the Gulf Coast, where they can be sold as an injectant for enhanced oil recovery. Part of the uncertainty arises from the difficulty in identifying, from among the large number of power plants and oil fields which could supply and demand the CO 2, which set would provide maximum profit for the pipeline companies, given the revenues expected from each, the feeder and gathering line construction costs, and the costs of shipment over existing trunklines. The profit-maximizing problem is viewed as a variant of the familiar knapsack problem, where the pipelines are viewed as containers to be filled by portions of differing volume and value per unit volume, transported, and emptied by dividing up their contents into portions of differing volume and value per unit volume. The problem is formulated, and a set of solution techniques examined. A real problem is solved, using a greedy algorithm.

Paradis CO2 Flood Gathering, Injection, and Production Systems

Summary Texaco U.S.A. has constructed a CO2 gathering and distribution system along with injection and production facilities for use in the Paradis field CO2 flood. The facilities were constructed concurrently and efficiently. They can be used readily for expansion of the injection into additional Paradis reservoirs. The systems have provided the operational reliability required for long-term projects. Modifications and maintenance have been minimal. The paper describes each system and discussesequipment and reasons for its selection andoperations history. Introduction CO2 injection began in Feb. 1982 in two reservoirs in the Paradis field, St. Charles Parish, LA (Fig. 1). However, the screening, planning, and design of the flood began in May 1979. The initial screening process to identify candidate reservoirs that were amenable to CO2 flooding required three months (Fig. 2). The reservoirs' producing histories and properties were reviewed and compared with guidelines for applying various EOR processes. Laboratory experimentation with reservoir fluid samples was begun. The planning and construction phases of project implementation required 30 months. The main objective of the planning phase was to determine the economic viability of the project. Estimates of equipment and operating cost were prepared. Actual bids for equipment and facility construction were received during project construction. The economics were updated as actual costs became available. Long-lead-time items for the various facilities, such as air emission permits, were applied for during the planning phase to avoid delays in construction. Frequent reviews of the project status were conducted to ensure that the project implementation went smoothly. Any commercial application of CO2 injection requires the securing of a long-term CO2 supply. The identification of such a source for the Paradis CO2 flood was conducted during the screening phase. The two sources were natural deposits in the Jackson Dome area of Mississippi and waste by product from industrial plants along the Mississippi River between Baton Rouge and New Orleans. The source selected was the by product from Monsanto Co. ammonia plants near Luling, LA. Equipment purchase and facilities construction did not begin until a purchase agreement was executed. CO2 Gathering System The CO2 gathering system consists of a gathering line, compression, dehydration, and metering facilities (Fig. 3). The system was constructed within the Monsanto Co.'s facility. Monsanto has two ammonia plants in operation that produce the CO2 as a waste by product. The flow data and an analysis of the gas produced by each plant are listed in Table 1. Plant 1 is 2,000 ft [610 m] from the compressor station site and Plant 2 is approximately 600 ft [183 m] away. To minimize Plant 2 is approximately 600 ft [183 m] away. To minimize the pressure drop, the gathering lines from each of the two plants are 24 in. [61 cm] in diameter. At the intersection plants are 24 in. [61 cm] in diameter. At the intersection of the two lines, the gathering line diameter increases to 30 in. [76 cm]. The gathering line is constructed of carbon steel pipe, which has the best structural attributes. Existing pipe supports and road crossings within the plant were used. pipe supports and road crossings within the plant were used. To protect the gathering line from the extremely corrosive wet CO2 and water that drops out in the line, the pipe was sandblasted internally and coated with an inorganic zinc primer and two epoxy top coats. The weld joints were primer and two epoxy top coats. The weld joints were wire-brushed and sealed with two brush-applied coats of coal tar epoxy. The piping system has not experienced any corrosion problems although it has only been in operation for a little problems although it has only been in operation for a little over 1 year. Stainless steel pipe was considered because of its corrosion resistance but was rejected because of its cost. Plastic pipe also was considered, but it is not structurally Plastic pipe also was considered, but it is not structurally strong enough for the required route through the plant. At the facility inlet, the saturated CO2 goes through a shell and tube inlet heat exchanger to cool the CO2 and knock out entrained water vapor. The heat exchanger was designed to provide a maximum temperature drop and be cost-efficient. It produces 30F [16.7C] temperature drop, which produces a corresponding drop in water content. From the heat exchanger, the CO2 passes to the inlet separator, which collects the water that falls out in the gathering line and heat exchanger. From the inlet separator, the CO2 goes to the suction manifold where it is picked up by the compressors. The suction pressure at the first stage cylinders on each unit is approximately 6 psig [41 kPa]. psig [41 kPa]. JPT p. 1312

The Development, Testing And Application of an Efficient Steady State Gas Field Performance Evaluation Model

Abstract Network theoretic concepts have been applied to the analysis and design of distribution network systems for some time. Notable applications include the analysis of water distribution networks, electrical network systems and, more recently, systems in the gas distribution industry. However, application ·of the technique to the simulation of natural gas field collection systems has been limited to the analysis of surface gathering configurations. This paper is an extension of this concept to allow for the inclusion of gas reservoirs and production strings. The paper presents the matrix formulation of the problem to Include all components of a natural gas gathering system. The application of the N-dimensional Newton-Raphson technique to the solution of the resulting system of nonlinear algebraic equations is discussed, and it includes an outline of a procedure that ensures convergence without the need for acceleration parameters. The application of the resulting model to an evaluation of the performance of a gas reservoir is given. The treatment includes, in addition to conventional analyses, the comprehensive evaluation of:the effect of liquid production on gathering and transmission line pressure drops; andthe effect of water influx on the performance and ultimate recovery from water-drive gas reservoirs. INTRODUCTION The increasing importance of natural gas in the energy supply spectrum demands comprehensive techniques for forecasting the future performance and deliverability of natural gas fields. The deliverability of natural gas fields is a function of pressure drops that occur in the reservoir, the production string and the surface facilities. Although it is possible to isolate each of these pressure drop segments for independent evaluation, the over-all performance of the total system and consequent optimum production plan for a natural gas field can best be determined through an evaluation that simultaneously considers the effect of all three pressure drops. Network theory provides a comprehensive and efficient means of achieving this objective. Literature Review A number of papers have appeared in the literature dealing with the forecasting of gas field deliverability and associated reservoir and gathering system performance. Dempsey et al.(1) proposed an iterative solution of the problem which consisted of two so-called subglobal iteration loops involving independent solution of the equations for the surface system, the production string and the reservoir. A compatibility test was necessary to match pressures and flow rates between iteration steps. The application of network theoretic concepts to the flow of fluid in networks has been reported in civil engineering literature(2,3) for water distribution systems and in electrical engineering literature for electrical networks(4,5,6). The formulation of problems using the concept of networks leads to a system of simultaneous algebraic equations. Iterative techniques must be used to obtain solutions to the unknowns when the system of equations is nonlinear. Application of network theoretic concepts to the simulation of natural gas gathering systems was first reported by Stoner(7) and more recently by Berard and Eliason(8). Stoner reported covergence problems in the iterative procedure and proposed the use of a heuris

Safety by Down-Hole Well Control

With a full understanding of the capabilities and limitations of down-hole safety valves, and with an adequate testing and maintenance program, operators can provide offshore platforms with total safety program, operators can provide offshore platforms with total safety systems that will minimize danger to lives, risk of pollution, and possible loss of investment. possible loss of investment. Introduction The oil industry's continuing endeavors to provide maximum protection against offshore disasters has lately been brought into the public eye as a result of an unusually high interest in preventing pollution. The development of offshore oilfields has been paralleled by a corresponding development in down-hole paralleled by a corresponding development in down-hole safety equipment designed not only to protect the environment but also to insure against loss of lives and damage to property. It is important that all persons dealing with it understand thoroughly the persons dealing with it understand thoroughly the capabilities and limitations of that equipment. Safety systems for offshore producing platforms can be divided into two general categories, surface safety systems and down-hole safety systems. Surface safety systems are the first line of protection against all minor mishaps or failures in control protection against all minor mishaps or failures in control systems, treating facilities, and process lines. They generally consist of valves - normally closed - in the vertical run of the producing well, in the flow line, or in some other gathering or service line. They protect against all routine malfunctions of equipment protect against all routine malfunctions of equipment on the platform or downstream of the platform. They can shut the well in at the wellhead or at any point in the system where a valve is located, and are readily accessible for repair and maintenance. Most surface safety valves in use today are of a type that does not depend on well pressure for closure. They are held open by low-pressure gas on one side of a piston that acts against a spring and line pressure acting on a smaller area. This low-pressure gas can be tied in to a network of control lines running to sensors installed at any point on the platform or beyond to detect abnormalities in platform conditions or malfunctions in equipment. Some of the many types in general use today are high- and low-pressure sensors, temperature sensors (fusible plugs), gas sniffers, and fluid-level sensors. Down-hole safety systems are commonly referred to as "catastrophe" systems because normally they are actuated (except for testing) only if the surface safety equipment fails or if there is an actual or imminent disaster on the platform. It is the final point of closure of the well. Down-Hole Safety Systems The first down-hole safety valve widely used was a simple poppet valve whose stem was held in the down (open) position by its own weight. Production flowed around the poppet and up through the body of the valve. When the flow rate increased enough to create a relatively low pressure above the poppet, the higher static pressure below it lifted the poppet up into the flow stream, which slammed it to the closed position. This valve was highly successful; but to predict its behavior was almost impossible. Also, the valve was very sensitive to surges, which would cause it to close prematurely. prematurely. A natural evolution from the poppet-type velocity valve was the differential pressure valve, commonly referred to as the "velocity valve" or Storm Choke. This type of valve, which is in use today in more wells than all other types combined, offers advantages over the original velocity valve in that it allows accurate calculation of closure, a wide range of settings, and resistance to surge closing. A relatively recent innovation in well-controlled valves is the "ambient pressure" valve, which is discussed in detail later. pressure" valve, which is discussed in detail later. JPT P. 263

Total Computer Simulation of a Gas Producing Complex

An ADI computer model is used to match the pressure-production history of a gas reservoir. Tied to this model is a steady-state model that, by locating energy sources and sinks, can help to determine the optimum investment scheme for a given gas gathering system. Introduction An accurate prediction of reservoir performance is of prime importance for all gas reservoirs. Equally prime importance for all gas reservoirs. Equally important is the ability to optimize investments and still obtain good reservoir performance. Failure to give proper consideration to investment factors will diminish the economic attractiveness of the reservoir. In addition, reservoir performance can be altered drastically by the flow facilities wells, flowlines, compressors that are available to produce and process gas. Adequate flow facilities must be present to permit good reservoir performance. Application of reservoir simulators to the study of reservoir behavior and investment planning is gaining a widespread appeal. An earlier paper by Henderson, Dempsey and Tyler discusses how well placement and reservoir operational strategy can be optimized by analysis with a reservoir simulator. In the present study the problem of investment planning is approached at a different level. This paper shows that required flow facilities can be optimized if the reservoir behavior can be predicted under various conditions. Rather than an idealized condition deigned to fit a reservoir model, this study is an actual field case history using observed and predicted data for a particular reservoir. particular reservoir. The location and amount of compression along a gathering line is determined for a certain reservoir production rate. Compressor stations are located at production rate. Compressor stations are located at various points on the gathering line. Also, consideration is given to various production rate schemes of certain poor gas wells in an effort to reduce the amount of poor gas wells in an effort to reduce the amount of compression necessary to operate the field. The reservoir performance was predicted using a two-dimensional single-phase simulator based on Eq. 1. (1) The gas gathering system predictions were solved using the well known Weymouth equation for flow of gas in a pipeline. The reservoir model is described in dear in Ref. 4. Statement of Problem This study was conducted on a dry gas sandstone reservoir containing 25 wells. The planned total reservoir withdrawal rate is shown in Fig. 1. The gathering system consists of a variety of pipelines linked together in a normal fashion and connected to a single downstream outlet (Fig, 4). Compression currently is installed at the downstream end of the gathering system, located at Site A. Earlier expectations indicated that additional compression would be located at the same station. This plan necessitates that gas from all wells in the gathering system be compressed. JPT P. 942

Automatic Custody-Transfer System at Lake Pelto, Louisiana

Abstract The production system and custody-transfer system for the Sun Oil Co.-Pure Oil Co. installation at Lake Pelto La., was designed to operate continuously and automatically to achieve maximum throughput with a minimum requirement for on-lease storage and manual attendance. Suitable equipment was installed in such a manner that all the wells can be controlled from a central production platform; their produced liquids can be processed continuously and delivered to the custody-transfer system with the assurance that all oil delivered is of merchantable quality. The custody-transfer system was designed to deliver oil automatically from the production system to the gathering line, using positive-displacement meters and related equipment for the measurement function. Introduction Everyone is aware that the cost of oil production and handling facilities in water locations is quite high. These costs have been trimmed a little through the years by more careful engineering, by prefabrication, and even by some attempts at mass production; today, however, the greatest hope for cost reduction lies in the use of newer improved oil-handling techniques. For this reason, in planning the facility to serve the Sun Oil Co. operated Louisiana State Lease 2620 in the Lake Pelto field, the design section was instructed to utilize automatic control systems and equipment wherever the application could be of economic or operational advantage. The full portent of this charge was realized when initial engineering estimates were summarized to showthat a continuous throughput design, utilizing automatic custody transfer, would reduce oil storage requirements 60 to 70 per cent compared to a conventional system andthat the additional cost of the equipment and controls necessary to make the operation continuous and completely automatic was approximately the same as the cost of 1,000 bbl of storage in this water location.