We don’t include a structure like the Eiffel Tower with separators, pumps, and compressors on the top observation platform in an onshore development plan. And yet, how many jacket platforms are there around the world? Production from an offshore Angola field has been decreasing because of subsea pressure declines amid water-cut increases and limited gas compressor capacity. The development process leading to the selection of high-boosting multiphase pumps is described. In maturing oil wells, oil production is often restricted as reservoir pressure depletes.
Unmanned minimum facility platforms are a reliable alternative to traditional wellhead platforms or subsea installations, and the technologies enabling simpler designs have evolved. Anadarko aims to maximize immediate short-cycle value through tiebacks and platform relocations in the Gulf of Mexico. This review of papers illustrates some of the innovative solutions used in the region. In maturing oil wells, oil production is often restricted as reservoir pressure depletes. Two case studies highlight the application of two-screw multiphase pump systems in to extend well life.
Aker Solutions and FSubsea have agreed to a joint venture, named FASTSubsea, to help operators increase oil recovery. Subsea pumps are used for gas/liquid separation, subsea compression, and subsea boosting. Solutions aiming at cost reductions are crucial to make subsea processing projects feasible. A cost- and complexity-reduction solution for the subsea electrical power supply is a critical consideration. In maturing oil wells, oil production is often restricted as reservoir pressure depletes.
Wang, Shuolong (College of Petroleum Engineering, China University of Petroleum-Beijing) | Wu, Xiaodong (College of Petroleum Engineering, China University of Petroleum-Beijing) | Han, Guoqing (College of Petroleum Engineering, China University of Petroleum-Beijing) | Ren, Zebin (College of Petroleum Engineering, China University of Petroleum-Beijing) | Tang, Jingfei (Schlumberger) | Wang, Hanlu (College of Petroleum Engineering, China University of Petroleum-Beijing)
Sliding vane pump (SVP) is a new type of all-metal rotary hydraulic pump, which is applied to high-temperature thermal recovery wells possessing high pump efficiency. A leakage model based on the mechanical structure of SVP is presented that employs the principles of fluid dynamics. The leakage gaps of each pump chamber are divided into three parts: the gap between vane and vane slot, the gap between vane and the upper and lower valve plate, and the gap between vane tip and stator inner wall. According to the flow characteristics of fluid in each gap, the correlation equations are established from the perspective of shear and pressure difference respectively. Meanwhile, the optimum allocation of SVP is provided via comparing different structure parameters of pump on the basis of operating characteristic, including stator-rotor eccentricity, rotor-groove radius and vane parity. The significant new finding shows that the greater stator-rotor eccentricity, the greater delivery capacity of SVP, and the disequilibrium of the bearing increasing simultaneously. Therefore, the application of stator-rotor eccentricity in oil field should take into account multiple factors, such as well structure and production mode. Moreover, on the premise of meeting the requirement of pump weight and sand control, rotor-groove radius should be minimized to reduce the adverse effect on volume efficiency. Furthermore, the more vanes of SVP, the smaller period, and the greater average value of instantaneous flow rate. The flow pulsation of SVP with odd vane number is less than it with even vane number, and the recommended number of vanes is 5 to 8.
Uetani, Takaaki (INPEX Corporation) | Furuichi, Naoto (INPEX Corporation) | Yorozu, Hirokazu (INPEX Corporation) | Sasaya, Kazuyo (INPEX Corporation) | Shibuya, Takehiro (INPEX Corporation) | Kiminami, Narihito (INPEX Corporation) | Yonebayashi, Hideharu (INPEX Corporation)
An oil well, referred to in this paper as Well B, experienced a serious emulsion problem soon after the introduction of artificial lift by use of a hydraulic jet pump. This forced the operator to reduce the production rate to meet sales-oil specifications. During its natural-flow-production period, this well experienced relatively emulsion-free operation. Consequently, the operator continued to use the same demulsifier after the jet-pump production began.
This paper presents results of a number of field trials that took place over a period of 1.5 years to control emulsions and to improve oil production. Initially, the operator raised the separator temperature, but this was not effective. Next, the operator injected xylene into the formation. Although this was reasonably successful, the effect was short term. It became necessary to open the separator-dump valve to drain the emulsions, and reduce the basic sediment and water (BS&W). This expensive operation was only undertaken to maintain production. The operator then explored changing the demulsifier-dosage rate and changing the location of the demulsifier-injection port, but neither measure was effective. Finally, a series of bottle tests was conducted to find a better demulsifier to replace the original chemical, which was no longer effective. Soon after injection of the new demulsifier, the emulsions disappeared, and the operator regained the production rate.
On the basis of the field observations and the preliminary laboratory investigations, it is determined that the emulsions that affected Well B over a period of 1.5 years were most likely caused by the introduction of artificial lift augmented by the continued use of the original demulsifier chemical, the increased production rate, and the presence of asphaltene and clay particles. An important lesson learned from this project was that emulsion-treatment programs should be reviewed periodically, especially when operating conditions change.
Some of the world's largest reserves are heavy oil reservoirs, defined as liquid petroleum of less than 20°API gravity or more than 0.2 Pa.s (200 cP) at reservoir conditions, [
In 2013, OneSubsea was awarded the Engineering, Procurement, and Construction (EPC) contract for Total's Moho 1bis development in the Republic of the Congo in West Africa. The contract included a subsea pump station with two 3.5 MW HighBoost pumps (helico-axial multiphase pump with balance piston) capable of handling high viscosities and gas volume fractions (GVFs).
As part of the Moho project, and to qualify the HighBoost technology for high viscosities, a full-scale test loop was built to verify pump performance at liquid viscosities up to 0.8 Pa.s (800cP). To cover the complete Moho operating range 0.001-0.8 Pa.s (1-800cP) and 0-75% GVF, the first article pump was tested on nitrogen and three different liquids: water, hydraulic oil, and gear oil. An extended analysis on the performance of helico-axial pumps in this unexplored domain of laminar and transition flow regimes was carried out.
Extensive amounts of test data were gathered during the 2-year qualification period. After testing and design optimization, the pump performance was significantly higher than predicted. The knowledge gained also served as valuable input to the pump protection logics customized for high-viscosity pumping. During the program the pump has proven its ability to perform startups on viscosities up to 30 Pa.s (30,000cP).
Qualification of this technology for high viscosity has widely extended the domain of high power, high flow and high differential pressure (dP) helico-axial multiphase pumps. Along with their proven track record in deep water and long step-out distances, the ability to pump high-viscosity fluid will enable future development of other heavy oil reserves going forward. The pump system described in this paper was successfully installed, commissioned, and started during the spring of 2017 to boost the viscous production. As of January 2018, it has been running with 100% availability following the startup.
Subsea development is a relatively recent concept associated with comparatively underresearched and unqualified technologies. The technological improvements necessary are characterized by requirements for severe service, multiphase handling, excellent reliability, and minimal, low-maintenance solutions.
Langbauer, C. (Montanuniversität Leoben, Department Petroleum Engineering) | Jax, G. (Montanuniversität Leoben, Department Petroleum Engineering) | Vita, P. (Montanuniversität Leoben, Department Petroleum Engineering) | Hofstätter, H. (Montanuniversität Leoben, Department Petroleum Engineering)
Conventional artificial lift systems are limited in their application by depth, borehole trajectory, and chemistry of the produced media. This paper presents a concentric tubular pumping system, combined with an efficient hydraulic pump to overcome the limitations of existing artificial lift systems and to assure a cost-effective production.
This pumping system consists of a specially designed pump&piston combination which is driven by a hydraulic pressure unit from the surface without any mechanical connection. The hydraulic pump itself can be circulated into and out of the borehole or can be run by slickline, resulting in fast and low-cost operations. The pump is designed to be run as a concentric tubular pumping system, which causes several advantages, especially in gas, thermal or chemical injection EOR installations. This new pump type is designed and manufactured in cooperation with the industry and tested at the Montanuniversität Leoben, Austria.
The performance and wear tests have demonstrated the saving potential in terms of energy efficiency as well as reduced CAPEX and OPEX. The unique design of this pump owns a very low number of moving parts, such no mechanical connection to the surface, and such providing minimal exposure to wear and corrosion. Tests have shown that the pump is very adaptable in terms of production rate, which just requires a change in surface hydraulic pressure. Based on experience the concentric tubular pumping system is the best selection for thermal and chemical EOR methods to enhance the lifetime of the completions. As a result of the natural phase separation of liquids and gases the presented pumping system has shown to be the ideal choice for the usage in all types of wells for gas injection EOR methods too.
This completely new pump type exceeds the performance of existing artificial lift systems, increases the mean time between failures and reduces the lifting costs essentially. These major issues are most important in times of low oil price, especially for tertiary recovery methods.
Al Silwadi, B. M. (Abu Dhabi Marine Operating Co.) | Al-Neaimi, A. K. (Abu Dhabi Marine Operating Co.) | Saif, O. (Abu Dhabi Marine Operating Co.) | Abed, A. A. (Abu Dhabi Marine Operating Co.) | Channa, Z. (Abu Dhabi Marine Operating Co.) | Sarsekov, A. (Abu Dhabi Marine Operating Co.) | McNeilly, K. (Abu Dhabi Marine Operating Co.)
The objective of this paper is to demonstrate the results of a study conducted on the nature of intermittent wells and the methodology to enhance unloading and reactivation operations. Intermittent wells are defined as wells demonstrating a production time period followed by a significant shut-in period. The study was conducted in an offshore carbonate field located in north-west Abu Dhabi, consisting of three major non-communicating sub-reservoirs separated by alternating dense layers. The study encompassed wells located in a low-pressure area of the reservoir.
The first aspect of this study encompasses an in-depth look at the different types of completion design utilized throughout the history of the field, specifically, the advantages and disadvantages of each type of completion.
The remaining aspect of this study is divided into two major categories, the enhancement of the inflow performance relationship (IPR) and the improvement of the vertical lift performance (VLP). The improvements of IPR are divided into the improvement of reservoir pressure, improvement of bottom hole flowing pressure, and improvement in wellbore damage. These improvements of IPR are briefly analyzed due to the minimal short term benefits. The main focus of this study is the enhancement of VLP for individual intermittent wells due to the instantaneous and rapid production gains and benefits. Additionally, the relationship between IPR and VLP is demonstrated through the use of prosper analysis.
During the current time period and condition of the field, the IPR of intermittent wells can be improved either by secondary recovery or by minimizing near wellbore damage. A case study of a vertical intermittent well is analyzed using pressure transient analysis to present the shift from a positive skin value to a negative skin value.
The main focus of this study is the enhancement of VLP for intermittent wells. This is due to the advantageous nature and rapid noticeability of benefits from improvements in VLP. The different challenges that inhibit VLP of intermittent wells are discussed, as well as, the major methods utilized to counter these challenges.
This paper will present possible solutions and improvements to prolong the production time, and thus, minimizing the downtime of these intermittent wells. Global solutions have been studied including decreasing the separator pressure from the main production complex in order to reduce the consequential backpressure, which in turn will reduce the flow-line pressure, and thus allow the intermittent wells to flow. Operational improvements have been analyzed such as utilizing equipment including larger diameter chokes in place of smaller chokes in order to decrease pressure losses. In addition, scaling and precipitates in relation to chokes are investigated.
The majority of the intermittent wells with a low success rate of unloading operations to reactivate wells are equipped with A3 velocity valves. These valves are problematic in an offshore environment due to the dependency on the flowline pressure and the production rate. When a well’s flow rate is decreased below the lower limit of the A3 valve, for any reason, the well will seize to flow, and thus categorized as intermittent, if this occurrence is common throughout the wells life.
The majority of the intermittent wells have seized flow due to low well head flowing pressures in comparison to the flow line pressure. Two major solutions have been determined. First, to reduce the main separator pressure by allowing slightly more gas into the liquid system and thus reducing the back-pressure created on the flow line. Second, an increase in the reservoir pressure has been achieved by closing in off-set wells during the production time of the intermittent wells. An alternating production and shut-in schedule has been developed to enhance productivity. This study is concluded by discussing the different types of equipment used to counter intermittency include surface ejectors and jet pump technology.
This paper will provide information and ideas to enhance the productivity, maximize the recovery, and prolong the production life of intermittent wells suffering from low well head pressure and malfunctioning equipment. This study is specifically relevant to reservoir production under low pressure mechanisms.
Artificial lift systems are among the most widely used production technologies in global oil and gas operations. Wells that cannot produce liquids to the surface under their own pressure require lift technologies to enable production. Some liquid wells need lift assistance from the beginning and almost all require it sooner or later.
In this paper, a poor-boy gas lifted well was replaced with a jet pumping system to enhance production. Well –2A was spud in July, 1984 and drilled to 14808 ft TD. After performing Drill Stem Test (DST), the well was completed with dual strings of 3-1/2 inche. It produced from Chorgali/Sakessar formations with an average 3,500 BOPD, 9.0 MMSCFD at 2,500 psi of WHP since 1985. However, the production declined to zero between 1991–1995, the well was revived on production, yet halted again. It was then brought back on production in 2002 and 2004, with the help of poor-boy gas lift, by tubing punches, but the water cut reached 100% during the lift and the well was shut in.
Well –2A was revitalized again on production by poor-boy gas lift, in which gas was injected through the ports of a jet pump Bottom Hole Assembly (BHA), after performing a work-over, where it was completed with a single string. Yet, because of repeated failure of the gas compressors, unavailability of high-pressure compressors and marginal production, the well was put on jet pump. The jet pump was run in hole with 12A Nozzle/Throat combination in free-style after ensuring sufficient liquid level within the wellbore.
Based on the results, a marginal well was optimized with the cumulative production of 820 BPD i.e., an average of 120 BOPD and 700 BWPD, which was higher than the targeted production rates evaluated for this well. A free-style jet pump deployment achieved the expected performance and reliability. Moreover, the jet pump can easily be re-optimized by reversing it out to change the nozzle and/or throat without requiring sick-line job.