Long Exposure Chelating Acid Treatment to Release ESP Stuck Pump

2021 ◽  
Author(s):  
Aliefiyan Nursanda Muklas ◽  
Candra Kurniawan ◽  
Hendra Kusuma ◽  
Bonni Ariwibowo ◽  
Prayudha Rifqi Safiraldi ◽  
...  
Keyword(s):  
Solution Treatment ◽  
Oil Production ◽  
Iron Deposit ◽  
Acid System ◽  
Common Solution ◽  
Well Production ◽  
Scale Deposit ◽  
Electrical Submersible Pump ◽  
Study Laboratory ◽  
First Time

Abstract In October 2019, electrical submersible pump (ESP) XY-107 experienced an overload shutdown. Troubleshooting actions have been conducted such as reverse rotation, used rocking method, voltage boost, inject gas through the annulus, and even fluid circulation, yet still failed to reactivate the well. Pump stuck condition was suspected and urgently need a solution. A study was performed to determine the cause of pump stuck. XY-107 is produced from limestone formation, therefore suggesting possibility of scale deposit formation in this well. Upon physical inspection inside the well's flowline, lump of deposit was recovered and suspect similar material could have occurred inside the pump. Rig intervention is a common solution for the ESP pump stuck condition. However, it required high cost (around 80,000 USD) and a longer well service job period up to 5 days. With scale deposit as the suspect, an unconventional solution was proposed to soak the well with acid to dissolve stuck-material by rigless operation. It was much cheaper than rig intervention (only about 4,000 USD) and with a shorter time of 1 day. Yet, acid selection is critical to avoid material damage during operation. Since conventional acid system is known to be corrosive to the metal components, hazardous, and difficult to handle; chelating acid was chosen as an alternative since it is known as a metal-friendly and able to dissolve carbonate and iron deposit. Treatment to address pump stuck situation was executed in March 2020. The chemical treatment was injected by pumping and circulating chelating solution from tubing to the annulus. ESP then soaked for 48-hours long. The treatment has successfully revived the well. It produced with no significant issue for 8 months and even double the oil production. This successful treatment proves chelating technique is safer for ESP and able to regain well production. Significant cost saving up to 76,000 USD was realized by avoiding rig intervention and shortening time of well services. Detailed study, laboratory testing, treatment procedure, and further analysis are discussed in this paper. Chelating acidizing is an uncommon acid system to stimulate carbonates and sandstone in our operating area. Since its successful performance during the trial, more acid campaign using chelating was conducted to enhance oil production. However, this acid system was never been tried as a solution treatment for pump stuck condition and the case of well XY-107 was the first time in the company's history.

scholarly journals Extraction new results of common fixed point theorems for $({T}, {\alpha }_{{s}}, {F})$-contraction of six mappings in a tripled b-metric space with an application of integral equations

2020 ◽  
Vol 2020 (1) ◽  
Author(s):  
Ghorban Khalilzadeh Ranjbar ◽  
Mohammad Esmael Samei
Keyword(s):  
Fixed Point ◽  
Common Fixed Point ◽  
Integral Equations ◽  
Metric Space ◽  
Fixed Point Theorems ◽  
Metric Spaces ◽  
Common Solution ◽  
Type Integral ◽  
First Time ◽  
Common Fixed Point Theorems

Abstract The aim of this work is to usher in tripled b-metric spaces, triple weakly $\alpha _{s}$ α s -admissible, triangular partially triple weakly $\alpha _{s}$ α s -admissible and their properties for the first time. Also, we prove some theorems about coincidence and common fixed point for six self-mappings. On the other hand, we present a new model, talk over an application of our results to establish the existence of common solution of the system of Volterra-type integral equations in a triple b-metric space. Also, we give some example to illustrate our theorems in the section of main results. Finally, we show an application of primary results.

scholarly journals Application of an Oil-Displacing Composition for Increasing Flow Rate of Low Producing High-Viscosity Oil Wells of the Usinskoye Oil Field

2016 ◽  
Vol 18 (2) ◽  
pp. 133
Author(s):  
L.K. Altunina ◽  
I.V. Kuvshinov ◽  
V.A. Kuvshinov ◽  
V.S. Ovsyannikova ◽  
D.I. Chuykina ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
High Viscosity ◽  
Oil Field ◽  
Thermal Methods ◽  
Cold Stimulation ◽  
Well Production ◽  
Well Stimulation ◽  
High Viscosity Oil ◽  
Stimulation Of

The results of a pilot application of a chemical composition for enhanced oil recovery developed at the IPC SB RAS are presented. The EOR-composition was tested in 2014 at the Permian-Carboniferous heavy oil deposit at the Usinskoye oil field. It is very effective for an increase in oil production rate and decrease in water cuttings of well production. In terms of the additionally produced oil, the resulting effect is up to 800 tons per well and its duration is up to 6 months. The application of technologies of low-productivity-well stimulation using the oil-displacing IKhNPRO system with controlled viscosity and alkalinity is thought to be promising. This composition is proposed for the cold’ stimulation of high-viscosity oil production as an alternative to thermal methods.

scholarly journals Generalized Extreme Value Statistics, Physical Scaling and Forecasts of Oil Production in the Bakken Shale

Energies ◽  
2019 ◽  
Vol 12 (19) ◽  
pp. 3641 ◽  
Author(s):  
Wardana Saputra ◽  
Wissem Kirati ◽  
Tadeusz Patzek
Keyword(s):  
Oil Production ◽  
Extreme Value ◽  
Gas Production ◽  
Extreme Value Statistics ◽  
Well Performance ◽  
Generalized Extreme Value ◽  
Potential Wells ◽  
Well Production ◽  
Industry Standard ◽  
Decline Curve

We aim to replace the current industry-standard empirical forecasts of oil production from hydrofractured horizontal wells in shales with a statistically and physically robust, accurate and precise method of matching historic well performance and predicting well production for up to two more decades. Our Bakken oil forecasting method extends the previous work on predicting fieldwide gas production in the Barnett shale and merges it with our new scaling of oil production in the Bakken. We first divide the existing 14,678 horizontal oil wells in the Bakken into 12 static samples in which reservoir quality and completion technologies are similar. For each sample, we use a purely data-driven non-parametric approach to arrive at an appropriate generalized extreme value (GEV) distribution of oil production from that sample’s dynamic well cohorts with at least 1 , 2 , 3 , ⋯ years on production. From these well cohorts, we stitch together the P 50 , P 10 , and P 90 statistical well prototypes for each sample. These statistical well prototypes are conditioned by well attrition, hydrofracture deterioration, pressure interference, well interference, progress in technology, and so forth. So far, there has been no physical scaling. Now we fit the parameters of our physical scaling model to the statistical well prototypes, and obtain a smooth extrapolation of oil production that is mechanistic, and not just a decline curve. At late times, we add radial inflow from the outside. By calculating the number of potential wells per square mile of each Bakken region (core and noncore), and scheduling future drilling programs, we stack up the extended well prototypes to obtain the plausible forecasts of oil production in the Bakken. We predict that Bakken will ultimately produce 5 billion barrels of oil from the existing wells, with the possible addition of 2 and 6 billion barrels from core and noncore areas, respectively.

DEVELOPMENT OF A FIELD MOBILE STANDARD OF THE 2ND CATEGORY AS A TOOL FOR VERIFYING WELL PRODUCTION MEASURING EQUIPMENT

2021 ◽  
Vol 7 (1) ◽  
pp. 163-176
Author(s):  
Vladimir E. VERSHININ ◽  
Sergey G. NIKULIN ◽  
Andrej A. Stupnikov
Keyword(s):  
Oil Recovery ◽  
Gas Flow ◽  
Oil Production ◽  
Production Optimization ◽  
Accuracy Class ◽  
Associated Gas ◽  
Well Production ◽  
Advantages And Disadvantages ◽  
Measuring Devices ◽  
Accuracy Of Measurements

In recent years, in the oil production industry there is a tendency of mass use of stationary multiphase metering units for determining oil, water, and associated gas flow rates in the recoverable well production. Automated group metering units, allowing to cover the whole group of wells in rotation metering mode, became widespread. The necessity of equipping wells with individual or group measuring devices is dictated, first of all, by the economic tasks of improving oil recovery factor and production optimization. In these conditions, the task of periodic verification of stationary measuring devices in the field with the help of mobile standards-measuring devices of higher accuracy class becomes urgent. The standard’s mobility and the need to work in the field with fluids of different composition significantly complicates the task of creating such a device. The practicality and economy of the created units first of all depends on a choice of a measuring method determining the design of the unit. This article analyzes the existing types of equipment for measuring oil, gas, and water consumption at the oil production wells. Showing the main advantages and disadvantages of each of them, this paper proves the necessity of using complex solutions based on different physical principles to improve the accuracy of measurements. The authors have proposed a combined scheme of a mobile standard of the 2nd category with a dynamic method for measuring the phase rates at the core. The unit performs a multi-stage partial separation of the input multiphase flow into liquid and gas phases and determines the fractions of water and oil in the liquid stream using a hydrostatic-type mixture composition analyzer. In addition, this article indicates the ways of increasing the accuracy of the measuring installation.

Hybrid Electrical-Submersible-Pump/Gas-Lift Application to Improve Heavy Oil Production: From System Design to Field Optimization

2021 ◽  
pp. 1-28
Author(s):  
Son Tran ◽  
Vu Le
Keyword(s):  
Service Life ◽  
Power Consumption ◽  
Heavy Oil ◽  
Oil Production ◽  
Production Optimization ◽  
Submersible Pump ◽  
Hybrid Mode ◽  
Field Development ◽  
Electrical Submersible Pump ◽  
Gas Lift

Abstract The typical challenge encountered in developing heavy-oil reservoirs is inefficient wellbore lifting caused by complex multiphase flows. The literature on modeling of a hybrid artificial lift (AL) system is relatively sparse and these works typically model the AL system on the basis of individual AL methods. This paper presents a case study of the design and optimization of a hybrid AL system to improve heavy-oil production. We systematically design and model a hybrid electrical-submersible-pump/gas-lift (ESP/GL) system to enhance wellbore lifting and production optimization. We found that the implementation of hybrid ESP/GL system provides the flexibility to boost production and reduces production downtime. Results from the pilot test show that the production rate in hybrid mode is approximately 30% higher than in ESP-only mode. The power consumption of the hybrid mode is 3% lower in the ESP-only mode. Furthermore, the average ESP service life exceeds six years which is better than expected in the field development plan. The pump-performance-curve model is built with corrections for density and viscosity owing to the increased water production. We observed a higher pressure drawdown with GL injection at fixed ESP frequency. The GL injection reduces the density of the fluid column above the ESP, resulting in less pressure loss across the pump, less power consumption, and potentially extended service life. The nodal-analysis results suggest that the pump capacity can be considerably expanded by manipulating the GL rate instead of increasing the frequency.

Addressing Matrix Acidizing Stimulation Challenges in Depleted, High-Temperature, and Acid-Sensitive Sandstone Formations with a High-Performance Acid System

2021 ◽  
Author(s):  
Rao Shafin Khan ◽  
Nestor Molero ◽  
Philippe Enkababian ◽  
Aizaz Khalid ◽  
Malik Anzar Afzal ◽  
...  
Keyword(s):  
High Temperature ◽  
Organic Acid ◽  
High Performance ◽  
Clay Content ◽  
High Energy ◽  
Acid System ◽  
Matrix Acidizing ◽  
Well Production ◽  
Production Trend ◽  
Sandstone Reservoirs

Abstract Acid stimulation in high-temperature sandstone reservoirs with high clay content can lead to undesired results due to secondary and tertiary reactions between treatment fluids and reservoir clays. Although there have been significant advancements in treating clastic formations over the years, high bottomhole temperature (BHT) coupled with high clay content of up to 35% and subhydrostatic conditions still presents a major challenge. A stimulation workflow to address these challenges was adapted to treat and successfully enhance well production in sandstone reservoirs in southern Pakistan. Candidate wells were selected for acidizing treatments based on declining production trend and identification of significant damage skin. X-ray diffraction tests on core samples indicated presence of acid-sensitive clays and calcite. Due to the risk of precipitation from secondary and tertiary reactions, conventional hydrochloric and hydrofluoric acid treatments were not viable options. Core flow testing was conducted to assess the efficiency of alternative acid systems at the reservoir conditions with BHT above 320°F, validating the selection of a high-performance sandstone acid system that was designed to handle undissolved clays in the critical matrix by helping to bind the clays to the pore surfaces, thus preventing them from migrating and plugging the pore throat during flowback. The matrix stimulation campaign included vertical and deviated dry gas wells, completed with 3 1/2-in. to 4 1/2-in. production tubing and 7-in. liner, with perforated intervals averaging 20 ft. Prior to the main acid treatment, high-pressure rotary jetting across the target intervals was conducted by pumping organic acid via coiled tubing. This wellbore conditioning technique allowed maximizing the acid performance by delivering 360° high-energy fluid to clear the perforations of scale and improve injectivity. The main treatment consisted of an organic acid preflush and a high-performance sandstone acid system as the main fluid, followed by a brine post-flush. Throughout the treatment, nitrogen was added to all fluids to facilitate fluid flowback under subhydrostatic conditions. The wells treated using this matrix stimulation engineered workflow yielded sustained production gains from 3 MMscf/D to 3.5 MMscf/D, exceeding expectations by more than 50% and achieving payback periods less than 20 days. The success of the treatment was largely due to the carefully designed stimulation workflow and its flawless execution. Acidizing high-temperature sandstone reservoirs with 30 to 35% clay content is uncommon. The experience gained in southern Pakistan validates the high-performance sandstone acid system as a reliable option for matrix acidizing in hot, acid-sensitive sandstone reservoirs. It also provides a detailed engineering workflow for candidate selection, treatment design, and job execution and evaluation, which can easily be adapted to regions facing similar challenges.

Subsea Oil and Gas Production Assurance Using Artificial Lifts and Nodal Analysis

2015 ◽  
Author(s):  
Ikenna A. Okaro ◽  
Longbin Tao
Keyword(s):  
System Analysis ◽  
Oil And Gas ◽  
Oil Production ◽  
Gas Production ◽  
Submersible Pump ◽  
Oil And Gas Production ◽  
Nodal Analysis ◽  
Multiphase Pump ◽  
Electrical Submersible Pump ◽  
The Impact

This paper describes how the operation of deep, subsea oil wells can be analyzed and optimized using artificial lift systems. A modest explanation was offered about an enhanced Hubbert model for determining production targets at pre-feed phase of project. In addition, the impact of artificial lifts on the economics of subsea wells facing hyperbolic production decline was illustrated. The principle of Nodal analysis was highlighted and applied to optimize a proposed subsea oil production case. Configurations of a nominally rated rod pump, a multiphase pump and an electrical submersible pump were modelled in a steady-state flow using Pipesim software and the simulated results which were functions of liquid flow rate and pressure distribution across the production system exposed the behavior of the system. The results showed that over 100% volumetric efficiency was achieved using a combination of electrical submersible pump at the bottom hole and a multiphase pump at riser base. A guide is presented on how to predict, analyze and enhance the recovery curve of subsea oil production using artificial lifts and nodal-system analysis. The benefit of this work is an enabling cost-effective approach for ensuring production assurance in deep water oil and gas production.

Experimental Study on Heat Yreatment Processing of a New Low Cost Titanium Alloy Used in Aviation Field

2013 ◽  
Vol 747-748 ◽  
pp. 919-925 ◽  
Author(s):  
Guo Qiang Shang ◽  
Xin Nan Wang ◽  
Yue Fei ◽  
Jun Li ◽  
Zhi Shou Zhu ◽  
...  
Keyword(s):  
Titanium Alloy ◽  
Low Cost ◽  
Solution Treatment ◽  
Heat Treating ◽  
Optical Microscope ◽  
Phase Region ◽  
Solution Temperature ◽  
Two Phase ◽  
Common Solution ◽  
Strength And Plasticity

The effect of common solution treatment, two-step solution treatment and aging, solution treatment and aging (STA) on the microstructure and mechanical properties of a new low cost titanium alloy used in aviation field were investigated by optical microscope (OM), scanning electron microscopy (SEM) and tensile test. The results show that a typical equiaxed structure can be obtained by common solution treatment leading to a good combination of strength and plasticity. Besides, solution heat treating in the β region and subsequently ageing at a low temperature results in a significant increase in mechanical strength and a little decrease in plasticity. When the solution temperature is at α+β two-phase region (895), the low cost titanium alloy acquires the best combination of strength and ductility.

scholarly journals Wyoming

2021 ◽  
Vol 7 (3) ◽  
pp. 472-479
Author(s):  
Jeffrey S. Pope ◽  
Deanna Sami Falzone
Keyword(s):  
Natural Gas ◽  
Crude Oil ◽  
Oil Production ◽  
Gas Production ◽  
Natural Gas Production ◽  
Crude Oil Production ◽  
Oil And Natural Gas ◽  
First Time

In 2019, Wyoming ranked eighth nationally in both crude oil and natural gas production. Sales of crude oil production totaled 101.8 million barrels, up 16% from 2018, while natural gas production totaled 1.456 trillion cubic feet, which was down 8.52% from 2018.1 However, as of August 1, 2020, Wyoming had zero oil and natural rigs in operation for the first time since 1884.

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