Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Summary Microprocessor-assisted programmable controllers have been installed as time-cycle control devices in Getty Oil Co.'s intermittent gas lift operation in the Ventura Avenue field. Electric clock intermitters located at each well site were replaced by centralized programmable controllers. intermittent gas lift cycles for 125 wells are now controlled by nine programmable controllers that use microprocessors as the timekeeping mechanism. With accurate control by the programmable controllers and the use of a specially designed computer program. individual well gas lift cycles are scheduled so that the demand for compressed gas at the compressor station is constant. A constant demand for compressed gas has eliminated compressor discharge rate and pressure fluctuations, therefore providing more efficient gas lift operations. In addition to accurate control of gas lift cycle timing, the centralized programmable controllers offer a much faster method of changing cycle length and cycle frequency. It is now more feasible to experiment with combinations of cycle length and frequency for each well to achieve the optimum gas-liquid ratio (GLR). As a result of more efficient well operations, the total system efficiency has improved, and compressor fuel gas requirements have dropped significantly. Introduction The Ventura Avenue field is located in southern California approximately two miles north of the city of Ventura in Ventura County (Fig. 1). Getty Oil Co. operates that portion of the field located at the east of the riverbottom area portion of the field located at the east of the riverbottom area of the Ventura River. The Ventura Avenue field produces from two major zones or "blocks"-C Block and D Block. Wells completed in C Block produce from depths between 5,000 and 8,000 ft [ 1.5 and 2.4 km]. D Block wells produce from 8,000 to 13,000 ft [2.4 to 4.0 km). The development of the D Block zones began in 193 1. Early development was rather slow owing to deep drilling problems, but active development continued into the early 1960's. Wells usually came in flowing at 200 to 900 BFPD [32 to 143 m3/d fluid] and continued to flow for 7 to 10 years. It was for these D Block wells that the current gas lift system originally was developed. Not only was there plenty of produced gas to be processed as fuel for the gas-fired compressor engines, but there was also plenty to be used in the compressors as recycle gas. The plenty to be used in the compressors as recycle gas. The wells were produced originally on continuous lift. but as production rates declined, intermittent lift proved to be production rates declined, intermittent lift proved to be more economic. D Block currently produces approximately 9,000 BFPD [ 1431 M3 /d fluid], 5,800 BFPD [922 m 3/d fluid] by rod pump and 3.200 BFPD [509 M3 /d fluid] by intermittent gas lift. Waterflood operations recently were initiated in D Block, although approximately 72 % of the current D Block production is still considered primary production. Many waterfloods ultimately will be primary production. Many waterfloods ultimately will be required to develop D Block because of numerous fault blocks and massive zone thickness (greater than 1,000 ft [300 m] in some wells) of D Block. The first D Block waterflood was initiated in Jan. 1980. injection into the second and third waterfloods began in Jan. 1983 and Dec. 1983, respectively. Eleven more potential D Block waterflood projects have been identified potential D Block waterflood projects have been identified for future consideration. A major impact of the waterflooding operations is the expected increase in fluid production and the corresponding decrease in gas production. An analysis was made to estimate the remaining effective life of the gas lift system operation in conjunction with the waterflooding operation. The analysis projected that the fuel gas and recycle gas required to lift the expected fluid volumes will be greater than the produced gas volumes within the next five years. Intermittent gas lift can be less expensive than rod pumping, especially at depths associated with D Block. pumping, especially at depths associated with D Block. For this reason, an investigation was conducted into ways to improve the efficiency of the current gas lift system operation, thus extending the remaining life of the system. The recommendations from the investigation were as follows.Conduct a diligent search for gas line leaks and repair immediately. optimize single-well GLR'S. Recycle gas requirements will be minimized, thus reducing fuel gas usage. Minimize compressor discharge pressure and rate fluctuations. A balanced system must be achieved for maximum system efficiency. On the basis of these recommendations, a search for gas line leaks was carried out. All lines were pressure tested and leaks repaired. Because of the age of the gas JPT P. 696
Abstract This paper proposes the use of pump-off controllers to optimize cyclic steam enhanced recovery. This is accomplished by allowing pumping units to operate at constant higher strokes per minute while letting the pump-off controller system monitor the fluid pound dictated by changing well conditions. This concept alleviates the need to change pumping unit speeds as the cycle progresses while ultimately increasing net oil progresses while ultimately increasing net oil gained per cycle. Introduction The heavy oil produced from the Midway-Sunset Field is stimulated by two methods: Steam Flood and cyclic Steam. A problem associated with cyclic steam enhanced recovery areas has been pumping wells off without sacrificing equipment, production, or man-hours. An average cycle, usually twice a year, consists of 6,000-8,000 bbls of steam injected at a rate of 1,000 bbls per day followed by a two day soaking period. Three methods that are used to solve the problem of pumping wells off earlier in the cycle are:change strokes per minute; variable speed-motors; and average production rate. As an alternative to all of these production rate. As an alternative to all of these methods the pump-off controller system will eliminate disadvantages associated-with the above methods and increase cycle efficiency while reducing run-time and related maintenance. Pump-off controllers were originated in the Texas and Gulf Coast areas where, due to the depth of the producing zones, fluid found is very destructive in rod pumped wells. in order to eliminate excessive maintenance caused by fluid pound, pump-of controllers were installed to shut wells down as soon as a fluid found was detected. Producing from depths associated with these areas, electrical power becomes a major expense, and by reducing run time, while not sacrificing production, electrical power costs can be reduced significantly. However, at Midway-Sunset these initial uses have little application. The producing wells are shallow, usually less than 2,000 feet, have very little reservoir pressure, and are maintained in a pumped off condition. Electrical power pumped off condition. Electrical power requirements are not a major expense associated with producing a well due to the low horsepower producing a well due to the low horsepower requirements (7.5-20 horsepower). DISCUSSION OF PROBLEM As stated above, the problem is how to most efficiently pump wells off aftercycling as early in the production cycle as possible. production rates that vary from 30 bbls per day gross before cycling to 300 bbls per day aftercycling create this unique pumping problem. Without a constant producing rate it becomes virtually impossible producing rate it becomes virtually impossible to set pumping speeds to accommodate both extremes. If the pumping speed is set to the higher initial production rates, then as the cycle progresses, production rates, then as the cycle progresses, severe fluid pound will result causing unnecessary maintenance. If the pumping speed is set to satisfy the lower production rate, it is obvious that there will be a production loss during the early stages of the production cycle. As a compromise, pumping speeds are often set to meet an average production-rate for the cycle life which eliminates the man-hours required to change pumping speeds. However, cycle efficiency is severely pumping speeds. However, cycle efficiency is severely reduced due to the increased time needed to produce the water back and achieve a pumped off produce the water back and achieve a pumped offcondition. Another alternative used is to mechanically change pumping speeds by changing sheave sizes. This does allow the well to produce at higher rates initially and as the cycle progresses, pumping speeds are changed according to the decreasing production rates. The man hours required to production rates. The man hours required to change sheaves, usually a minimum of two times percycle, becomes an added expense and efficiency per cycle, becomes an added expense and efficiency is still lost. P. 297
Abstract With increasing wells connected to central facilities, it is hard to manage water flood using traditional technique. Therefore, a novel control concept named Swinging Water Injection Targets (SWIT) was developed in PDO to manage the challenges and satisfies both surface/subsurface requirements. The objectives of SWIT are: Maximize water injection well compliance. Minimize oil deferment due to water disposal restriction. Automated system that manages the variations in produced water flow with minimum interventions. SWIT concept is using the tolerance of ยฑ 20% of desired injection target (Compliance limit) for each water injection (WI) well. So rather than having a fixed target, a minimum and maximum injection flow are giving to each WI well flow controller. Those range are provided by subsurface to ensure minimal impact for the rate fluctuation. The injection flows are driven by WI header pressure controller. When the produced water, the WI header pressure increases then the pressure controller to control the pressure asks all WI wells simultaneously increasing their injection flow at the same relative portion (Optimized distribution). Also, when the produced water decreases all WI flow starts reducing in the same way. SWIT concept proved success in PDO and it became a standard. It was first introduced in small field. Later, it was replicated across the company fields. The biggest scale implementation was in a cluster with more than 500 WI wells. Previously, in that cluster the WI header pressure was fluctuating indicating issues with water balance. Many manual adjustments were required to manage the situations when the produced water is more than the injection demand by closing oil producers leading to a considerable deferment due to water disposal restriction. Also, when the supply water is less than injection demand many WI wells start under injecting leading to low injection compliance. After SWIT was introduced in the cluster and all injectors started swinging in harmony via automatic control, it managed to balance the water system (controlled WI header pressure) regardless of the variation in produced water production. This resulted in increase of WI compliance by 5% after implementation. As SWIT optimized the water distribution to the injectors, roughly around 50 m3/d of additional oil production was achieved. It also minimized deferment from disposal restriction to a minimum level. All of this without the hustle of manual interventions.
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
From the Wolfcamp and Bone Spring in the Permian Basin to the Niobrara and Codell in the Denver-Julesburg Basin, lateral lengths of 10,000 ft or greater are becoming the norm in tight-oil resource plays (Rassenfoss 2022; Addison, 2021; S&P 2021). From a production standpoint, longer laterals equate to greater stimulated rock volume per wellbore. That means higher flow rates, but it can also introduce more dynamic behavior and steeper production declines. The extended-well trajectories are often accompanied by high dogleg severities, high gas/oil ratios (GORs), and sand and solids production (Whitfield 2023; S&P 2021). Efficiently accommodating all of these factors while cost-effectively managing natural declines over time can be a challenge for any single artificial lift method. However, the combination of gas lift and plunger lift technology gives operators a flexible option to optimize production beginning with initial peak flow rates at the start of production and extending all the way through to depletion. This โfull life cycleโ approach encompasses three distinct phases that collectively span the entire slope of the tight-oil well decline curve: - Gas lift in early to mid-life (from first production to ยฑ300 B/D) - Plunger-assisted gas lift (PAGL) in the mid- to late-life plateau (from ยฑ300 to ยฑ100 B/D) - Plunger lift in late life (from ยฑ100 B/D to last oil) An artificial lift approach leveraging gas lift, PAGL, and plunger lift at different points along the production timeline aggregately brings the key advantages of all three to bear in horizontal tight-oil wells, including - Gas liftโs ability to mimic natural reservoir flow, lifting fluids to surface by reducing the flowing tubing pressure and creating differential pressure between the reservoir and wellbore. Gas lift handles an array of production rates (up to 2,000-plus B/D) and well characteristicsโincluding high GORs and solid contentโand can adapt to rapidly changing conditions during early well life. - PAGLโs ability to increase reservoir drawdown, stabilize production, and reduce system surging as production diminishes to the point where gas lift starts to become inefficient in the mid-life phase. - Plunger liftโs ability to use pressure buildup below the plunger to carry accumulated fluids to surface at rates as low as a few B/D, requiring no external power source to surface the plunger. The plunger creates a โswabbing effectโ as it passes through the tubing that helps draw fluids from perforated intervals while keeping tubing swept of paraffin, scale, asphaltene, sand, etc.
- North America > United States > Texas (0.50)
- North America > United States > New Mexico (0.36)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (30 more...)
Abstract For oilfield with high associated gas production or non-associated gas (NAG) wells, gas injection is typically being given as priority, and only the resulting gas flow not taken by injection wells is exported as sales gas. With the unstable price of oil and the shift towards gas as cleaner energy source thus creating higher gas demand, the produced gas maybe prioritized for sales rather than for injection. This paper demonstrates the new approach of managing the gas export and gas injection including the flexibility in prioritizing either utilization options, and managing the impact of changes in injection gas supply accordingly via process analytics and automation. The paper described the concept and key design consideration in integrating the gas injection and gas export process analytics and control in oil and gas fields for improved hydrocarbon recovery application and flexibility of operation modes. It also described step-by-step approach for the technology development and adoption, which is a commendable to be replicated for other production system. Based on a case study, current operation gaps, limitation and opportunity are identified from system review, followed by development of automation strategy, mainly focusing at utilizing the current instrumentations available at the field to manage the gas export and injection accordingly based on desired prioritized mode. With the automation exercise, the operator can now control the system by changing the priority mode and set points at DCS rather than manually adjusting the choke valves opening to regulate the gas injection and gas export flow.