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Blackmer's S Series of twin and triple screw pumps are self-priming, double-ended positive displacement pumps whose design provides complete axial balancing of the rotating screws and whose timing technologies eliminate metal-to-metal contact with the pump. They are ATEX-certified for use in explosive or dangerous environments. The pumps are available in four distinct lines, each having multiple model configurations and sizes: twin screw (WTG), twin screw with non-timing gear (NTG), multi-phase twin screw, and triple screw.
Development of jet-powered devices for energy effective oil and gas production technologies (Russian)
Sazonov, U. A. (Russian State University of Oil and Gas (National Research University), RF, Moscow) | Mokhov, M. A. (Russian State University of Oil and Gas (National Research University), RF, Moscow) | Mischenko, I. T. (Russian State University of Oil and Gas (National Research University), RF, Moscow) | Drozdov, A. N. (Russian State University of Oil and Gas (National Research University), RF, Moscow)
The PDF file of this paper is in Russian. Energy saving technological processes is one of the most actual objectives of the entire Russian industry and oil and gas sector in particular. For these purposes creation of jet-powered equipment might be considered as a perspective direction of science and technology development. Jet-powered equipment may be effectively used in a pump mode, compressor mode and multiphase pump mode when pumping gas-liquid mixtures with solid particles in a stream, applied to low and high viscous environments. Simple construction of jet-powered devices allows for significant reduce in cost and increase in reliability. In order to solve direct and inverse hydrodynamical jet-powered devices theory problems the set of computer programs is created. Accumulated practical experience combined with theoretical studies allowed to set up serial production of jet-powered devices. Usage of jet-powered devices for creation of Humphrey cycle heat engines considered as a perspective direction of jet-powered devices studies. Further studies aimed at usage of stationary jet-powered pumping and compressor plants for preliminary compression of air-fuel mixture up to the pressure of 0,5 MPa. Instead of flaring the associated gas, hydrocarbons energy might be effectively converted to work output using Humphrey cycle for oil and gas production and transportation, increased separation efficiency and other objectives.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 187283, “Eliminate Decision Bias in Facilities Planning,” by Z. Cristea, Stochastic Asset Management, and T. Cristea, Consultant, prepared for the 2017 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8–11 October. The paper has not been peer reviewed. The complete paper holds the traditional facilities-planning methodologies, heavily based on design-basis documents and biased toward the most-conservative conditions, fail to recognize the entirety of operational conditions throughout the oilfield life cycle, leading to significant residual risk and the wastage of resources in the operations stage. An integrated stochastic approach is proposed, accounting for both subsurface and surface uncertainties and their interrelations throughout field life. Introduction The authors discuss an unbiased, data-driven stochastic work flow addressing the effect of subsurface uncertainties on surface-facilities design and operational decisions. Unlike classical design approaches, in which the most-conservative values are typically used as design input variables and assembled into design-basis documents, the stochastic work flow accounts for design-input-variable distribution and combination throughout the entire system life cycle. An example case is provided in which a flow-assurance risk is managed and chemical consumption optimized in a wet-gas field development. Theory and Definitions Oil and gas engineering projects are typically processes of high variety, low volume, and intermittent productivity, and with a high rate of diversification and complexity. Conversely, oilfield-facilities operations are expected to be continuous, characterized by high volumes and low variety. This expectation is reflected in the approach toward facilities design, where single-point, “conservative” design conditions are proposed and assembled as facilities design-basis documents. This approach frequently fails to recognize the risks and uncertainties associated with oilfield developments. In the proposed work flow, deterministic models are established to account for the dependencies between design input variables {static variables [i.e., bottomhole pressure (BHP) and bottomhole temperature (BHT)]} and the desired objective [static results (i.e., chemical- injection rate)]. In the provided example, the analyzed variables change because of subsurface and surface events with different levels of uncertainty (i.e., condensate banking, lean-gas injection, water breakthrough). Stochastic algorithms are used to create probability-distribution functions (PDFs) for all analyzed design input variables (stochastic variables). Stochastic algorithms are then applied in the deterministic model, sampling from the previously defined probability distributions. Stochastic results are assembled into insightful charts and used to analyze the most-relevant variables and correlations affecting the objective function.
- Summary/Review (0.55)
- Research Report (0.49)
During oil production in mature fields, the implementation of waterflooding projects plays an important role in increasing oil production and the recovery factor of the reservoirs, and this is the case in the Golfo San Jorge Basin (GSJB) in Patagonia, Argentina. As part of a comprehensive water-management strategy, this paper describes different process and operational considerations that are the result of 109 years of production in Argentina's oldest basin. The production history of the GSJB has included water production from the beginning, although, in recent years, the volumes have been increasing. The objective of water management has been to maximize the value of the assets by increasing oil production and the reserves recovery factor, reducing the production cost, and limiting or canceling environmental effects. In terms of production, the water associated with oil is collected in production batteries and transferred to treatment and injection plants (Figure 1 above).
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Well Operations and Optimization > Produced water management and control (1.00)
- Production and Well Operations > Artificial Lift Systems (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (0.97)
Abstract Poor recovery of oil rims is a common challenge for most operators. The reasons are inherent subsurface risks and capital intensive EOR and IOR projects. This paper presents a similar case of reservoir with oil rim where a cost effective method was employed to increase oil recovery. The idea was to inject high pressure gas from a shallower gas reservoir into zone with oil rim. The case study is about B Field located in Sindh Province of Pakistan discovered through drilling of well B-1 in 1989. The well encountered hydrocarbon bearing Lower Goru X&Y Sands. Formation testing results and Open-hole logs showed X Sand to be gas bearing, whereas, Y Sand found thin oil rim overlain by gas cap. B-1 was put on production from Y Sand and it flowed at around 300 bopd with 500 scf/stb GOR. However, rapid decline in oil rates and reservoir pressure was witnessed due to gas coning. Based on engineering and G&G analysis, it was decided to re-pressurize oil rim in Y Sand using gas of X Sand at virgin pressure. Considering Y Sand to be laterally extensive body, effect of gas injection at B-1 should be observed at wells B-2 and B-6 in the same structure. Nodal analysis was performed to estimate injection rate while tank models were used to estimate additional recovery. The X Sand was then perforated and cross-flow established. Performance of gas injection was monitored through surveillance at B-2 and B-6 that recorded increasing Y Sand pressures. Success of in-situ gas injection was established as considerable improvement in oil recovery was achieved. In-situ gas injection, wherever applicable, could be an efficient technique to maintain reservoir pressure of oil reservoir without additional surface footprints or facilities thus incurring marginal capital expenditure. The efficacy of this technique could be easily monitored through regular surveillance and well production behavior.
- Asia > Indonesia > East Kalimantan > Makassar Strait > Kutei Basin > Attaka Field (0.99)
- Asia > Pakistan > Sindh > Indus Basin > Badin Block > Badin Field (0.98)
Issues and Challenges With Controlling Large Drawdown in the First Offshore Methane-Hydrate Production Test
Sakurai, S.. (Japan Oil, Gas and Metals National Corporation) | Nishioka, I.. (Japan Oil, Gas and Metals National Corporation) | Matsuzawa, M.. (Japan Drilling Company Limited) | Matzain, B.. ((currently with Amaray)) | Goto, A.. ((currently with Japan Petroleum Exploration Company Limited)) | Lee, J. E. (Schlumberger)
Summary The first offshore methane-hydrate production test was conducted in the Eastern Nankai Trough area of Japan in 2013, subjecting a gas-hydrates reservoir to large drawdowns by reducing bottomhole pressure (BHP) for in-situ dissociation of gas hydrates. This pioneering test has proved the feasibility of the depressurization method through demonstration of gas production from a deepwater gas-hydrates reservoir. Approximately 119 500 std m of gas was produced during a continuous flow period of 6 days. However, reservoir response to a range of drawdown conditions was not attainable, which is important for reservoir evaluation, because drawdown became uncontrollable after unintended water production through the gas line occurred. Gas and water released from the dissociation of gas hydrates were separated by use of a downhole gas-separation system. The separated gas and water were produced to surface by means of two dedicated gas and water lines. Drawdown was executed by pumping out water into the water line by use of an electrical submersible pump (ESP). Drawdown control was designed to regulate the liquid level (or hydrostatic pressure) in the gas line by controlling the ESP frequency and the water-line surface backpressure. Analysis of production data supported by flow simulations indicated that continuous water production through the gas line was the main reason for the loss of drawdown control. The trigger of the water production was that the water column in the gas line reached surface because of the rising water level resulting from the produced gas, which also lightened the water column and lowered the BHP. Consequently, the continuous water production made it difficult to regulate the drawdown as intended. The analysis concluded that the risk of water production through the gas line could be significantly lowered if a choke valve was installed at the surface gas line and/or the ESP had high tolerance to the presence of free gas. This first field trial has provided valuable information in understanding the methane-hydrate production system to further improve/develop strategies in controlling large drawdown in the system.
- North America (1.00)
- Asia > Japan (1.00)
- South America > Brazil > Espírito Santo > South Atlantic Ocean > Campos Basin > Block BC-10 > Parque das Conchas Field (0.97)
- South America > Brazil > Brazil > South Atlantic Ocean (0.91)
- Reservoir Description and Dynamics > Non-Traditional Resources > Gas hydrates (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well Operations and Optimization > Produced water management and control (1.00)
- (2 more...)
Field Trial of a Novel Self-Reciprocating Hydraulic Pump for Deliquification
Romer, M. C. (ExxonMobil Upstream Research) | Brown, M.. (XTO Energy) | Ainsworth, N.. (XTO Energy) | Rundberg, O.. (XTO Energy) | Bolt, D. J. (Cormorant Engineering) | Bolt, T.. (Cormorant Engineering) | Tolman, R. C. (RC Tolman LLC)
Summary A novel hydraulically powered, self-reciprocating valve pump (SRVP) was piloted in a western Colorado gas well for deliquification operations. The objective was to pump liquids from a deep gas well and later retrieve and redeploy the SRVP without a workover rig. This paper will describe the SRVP technology, areas of applicability, and pilot program, including the completion design, deployment/retrieval workovers, performance, teardowns, learnings, and future plans. Gas-production wells tend to load up with produced or condensed liquids that create an impediment to flow and reduce or stop gas production. Pumps are typically used when the reservoir pressure is too low for less-intrusive artificial-lift (AL) methods or when significant amounts of liquid must be removed. Pumps can suffer from reliability issues and considerable installation/deployment costs because a workover rig is typically required for intervention. Unfavorable producing conditions and tortuous wellbore trajectories tend to further decrease run lives. These issues can make economical hydrocarbon production impossible. The SRVP was developed to overcome these challenges. The SRVP is installed downhole inside a concentric tubing string, and is powered by injecting a high-pressure liquid. The injected (power) fluid causes the SRVP to reciprocate, driving a piston pump to produce formation fluids and to power fluid back to the surface up the concentric-string/production-tubing annulus. The removal of the produced fluids decreases the backpressure on the formation, enabling gas production up the casing. Because there is no mechanical linkage to the surface for pump operation, the SRVP can be deployed in highly deviated and/or small-diameter wells with which standard AL methods would struggle. In addition, the SRVP is designed to be pumped into and out of the well after initial installation, greatly reducing deployment costs. Three industry-first SRVPs were installed consecutively in a concentric flush-joint tubing string, and were powered with a compact surface pumping unit. The SRVP proved the ability to lift 20 to 40 BFPD net liquids up the concentric-string/production-tubing annulus from more than a 12,000-ft vertical depth while gas was produced up the casing. The SRVP was retrieved and redeployed several times either hydraulically and/or with slickline (SL). System design, operation, and performance were continuously improved through the duration of the pilot program. Run life steadily increased to more than 50 days with the third installation.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > Utah > Uinta Basin (0.99)
- North America > United States > Colorado > Uinta Basin (0.99)
- (2 more...)
Scaled Experimental and Simulation Study of Segregation in Water-Above-Gas Injection
Namani, Mehran ((currently with Statoil ASA)) | Souraki, Yaser ((currently with Repsol S.A.)) | Kleppe, Jon ((currently with Statoil ASA)) | Høier, Lars ((currently with Statoil ASA)) | Karimaie, Hassan ((currently with First Geo), Norwegian University of Science and Technology)
Summary The water-above-gas injection has been introduced as a modified injection strategy for simultaneous or alternating water/gas injection to improve the recovery factor. This can be achieved through maximizing the size of the mixed zone and extending the complete-segregation distance. Verifying this approach in the laboratory needs special experimental design in which the effect of capillary force is eliminated or strongly reduced, and viscous and gravity forces are active. In this study, an experimental setup has been prepared and implemented to verify the advantages of the water-above-gas injection. Key parameters in this experiment have been scaled to reservoir conditions. This was possible through choosing correct porous media and fluid system. The porous media should have high porosity and permeability, and the fluid system should have very low interfacial tension (IFT) between phases. Supplementary experiments have been conducted to prove the reliability of the model before the main experiment. In addition to the investigation of different injection rates and water/gas injection ratios in this process, the effect of stepwise injection also has been investigated to verify the practical approach, which results in maximized sweep efficiency. Finally, a simulation study has been conducted, and by comparing its results to experimental results, the applicability of numerical simulation in designing reservoir-scale water-above-gas injection is confirmed.
- Europe > Norway (0.46)
- Asia > Middle East > Iran (0.28)
- North America > United States (0.28)
- North America > Mexico (0.28)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Heather Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Fensfjord Formation (0.99)
- (9 more...)
Summary After gas wells are drilled and start producing, early production rates are high enough to carry any liquid produced to the surface. However, as the reservoir pressure declines, the gas-production rate also declines. Eventually, the gas well starts experiencing liquid loading. Liquid loading starts when the current gas rate is incapable of lifting the liquid up to the surface. The liquid can be either water produced from the formation or the condensate. Several correlations in the literature predict the onset of liquid loading. The most famous equation, the Turner et al. (1969) equation, has many limitations, including the inability to account for effects such as diameter of the pipe and inclination angle of well, and incorrect physical assumptions regarding the onset of liquid loading. Belfroid et al. (2008) modified the Turner et al. (1969) equation for inclined wells; however, their expression is also dependent on incorrect physical assumptions and does not account for the diameter of the pipe. Another method, proposed by Shu et al. (2014), uses the correct physical assumption of liquid loading, but is overly conservative. This paper discusses a new modification to the original method proposed by Barnea (1986), which overcomes many limitations of the previous models. The new method is dependent on an assumption that liquid loading initiates when the liquid film starts falling backward. The proposed method accounts for the effect of diameter and inclination angle of the gas well. The method predicts the onset of liquid loading for a wide range of inclination angles, from vertical well to nearly horizontal well. The application of the method has been verified by comparing the results with both laboratory and field data. The method is observed to be better at predicting the onset of liquid loading compared with the other existing models in the literature.
- Overview > Innovation (0.92)
- Research Report (0.88)
Low Pressure Operation LPO: Extending Field Life of Several High H2S Fields with Minimum Costs
Hadhrami, A.. (Petroleum Development Oman) | Mihajlov, R.. (Petroleum Development Oman) | Muthalaly, M.. (Petroleum Development Oman) | Schulz, R.. (Petroleum Development Oman) | Alias, Z.. (Petroleum Development Oman) | Riyami, A.. (Petroleum Development Oman) | Abri, Z.. (Petroleum Development Oman)
Abstract Several high pressure (up to 1000 bar), deep (3-5 km) and high sour oil (H2S/CO2 up to 10%/25%) fields have been in primary depletion production in the Southern Sour Cluster in Petroleum Development Oman (PDO) for the last several years. These fields are currently nearing lift-die out or have already experienced lift die out. These carbonate (and silycillite) fields form stringers which are encapsulated by salt and thus lack natural aquifer support. The only drive mechanism has been up to now fluid (and rock) expansion. Artificial lift in form of high cost Electrical Submersible Pumps (ESPs) was attempted in 3 wells and failed due to suspected design and installation issues, including depth of the reservoir. To extend the depletion production life a Low Pressure Operation (LPO) has been proposed across all the 3 stations within the cluster and all currently being executed. LPO makes smart and sustainable use of existing facilities by simply re-routing incoming trunk line in three stations to the low pressure separator. Several other options were screened but were found to be less attractive. LPO will allow continuation of depletion production for several years until Miscible Gas Injection (MGI) is implemented as a next development phase. LPO concept is commercially extremely attractive with very low Unit Technical Costs (UTCs) of less than $10/bbls and high Value Investment Ratio (VIR) of more than 20.
- North America > United States (0.47)
- Asia > Middle East > Oman (0.26)