Laboratory And Field Data Indicate Water Base Drilling Fluids That Resist Differential-Pressure Pipe Sticking

1978 ◽  
Author(s):  
Dan Hunter ◽  
NL. Baroid ◽  
Neal Adams
Keyword(s):  
Field Data ◽  
Differential Pressure ◽  
Drilling Fluids ◽  
Pressure Pipe ◽  
Water Base

Pipe stick problems of deep well drilling

2021 ◽  
Vol 66 (05) ◽  
pp. 192-195
Author(s):  
Rövşən Azər oğlu İsmayılov ◽  
Keyword(s):  
Drilling Fluid ◽  
Drill Pipe ◽  
Drill String ◽  
Differential Pressure ◽  
Drilling Mud ◽  
Fluid Circulation ◽  
Well Drilling ◽  
Deep Well ◽  
Pressure Pipe ◽  
Bottomhole Pressure

The aricle is about the pipe stick problems of deep well drilling. Pipe stick problem is one of the drilling problems. There are two types of pipe stick problems exist. One of them is differential pressure pipe sticking. Another one of them is mechanical pipe sticking. There are a lot of reasons for pipe stick problems. Indigators of differential pressure sticking are increase in torque and drug forces, inability to reciprocate drill string and uninterrupted drilling fluid circulation. Key words: pipe stick, mecanical pipe stick,difference of pressure, drill pipe, drilling mud, bottomhole pressure, formation pressure

scholarly journals Design of PLC Integrated Process Simulation Software for Steam Generator Using Matlab Simulink

2018 ◽  
Vol 43 ◽  
pp. 01012
Author(s):  
Ikhtiander ◽  
Soekirno Santoso
Keyword(s):  
Steam Generator ◽  
Flow Rate ◽  
Field Data ◽  
Volume Flow ◽  
Differential Pressure ◽  
Steam Quality ◽  
Fuel Gas ◽  
Matlab Simulink ◽  
Simulator Program ◽  
Error Percentage

This paper describes the work done in order to make Matlab Simulink based steam generator simulator in the simulation of a steam generator. The steam generator under this research is operated with the steam quality of 72%, O2 content is 1.2%, designed steam volume flow is 3600 barrel per day at a maximum and designed fuel gas volume flow is 1300 Thousand Standard Cubic Feet (MSCF) per day at a maximum. The simulator program of the steam generator is separated into individual components consisting of Burner, Radiant, Convection, Exhaust Stack, Feedwater Pump Discharge and Steam Discharge. Within the components, thermodynamics and heat transfer principles such as conduction, convection, radiation and also conservation of mass, momentum, and energy were applied to compute the pressure values, temperature values, and flow rate values of simulated field device based on the command and setpoint from PLC. The validation process has been done with the steam generator is operating in a steady state to the 10 important process parameters of the steam generator. The error percentage calculated from a difference between the simulation result value and the actual value from field data reference divide by actual value from field data reference. The error percentage results are as following : Fuel Gas Orifice Differential Pressure : 2.39%, Fuel Gas Pressure : 1.37%, Fuel Gas Temperature : 5.95%, Fuel Gas Flow Rate : 1.25%, Feedwater Orifice Differential Pressure : 1.94%, Feedwater Pressure : 1.54%, Feedwater Flow Rate : 0.92%, Steam Orifice Differential Pressure 3.26%, Steam Discharge Pressure 1.93% and Steam Quality : 0.05%.

scholarly journals Study on Ultrafine Particles Used in Drilling Fluids

2020 ◽  
Vol 319 ◽  
pp. 05002
Author(s):  
X C Cao ◽  
C. Y. Zhou ◽  
Y. Y. Li ◽  
W Zong ◽  
J Wang ◽  
...  
Keyword(s):  
Titanium Dioxide ◽  
Calcium Carbonate ◽  
Ultrafine Particles ◽  
Drilling Fluids ◽  
Viscosity Property ◽  
Water Base

In this paper, several ultrafine particles were prepared and characterized, then the performance of drilling fluids were evaluated after ultrafine particles were added in water base drilling fluids. The viscosity property of drilling fluids were increased, however, filtration reduction could not be strictly controlled. All filtration volume was difficult to control just like common ultrafine calcium carbonate unless some polymers could be used. Titanium dioxide and zinc dioxide could be used as substitutes of calcium carbonate in drilling fluids.

Risk Due to Pipe Sticking

2014 ◽  
pp. 47-72
Author(s):  
Nediljka Gaurina-Medjimurec ◽  
Borivoje Pasic
Keyword(s):  
Petroleum Industry ◽  
Drill String ◽  
Differential Pressure ◽  
Factors Affecting ◽  
Wellbore Instability ◽  
Hole Cleaning ◽  
Pressure Pipe ◽  
Drilling Parameters ◽  
Bottom Hole Assembly ◽  
Geometry Deviation

A stuck pipe is a common worldwide drilling problem in terms of time and financial cost. It causes significant increases in non-productive time and losses of millions of dollars each year in the petroleum industry. There are many factors affecting stuck pipe occurrence such as improper mud design, poor hole cleaning, differential pressure, key seating, balling up of bit, accumulation of cuttings, poor bottom hole assembly configuration, etc. The causes of a stuck pipe can be divided into two categories: (a) differential sticking and (b) mechanical sticking. Differential-pressure pipe sticking occurs when a portion of the drill string becomes embedded in a filter cake that forms on the wall of a permeable formation during drilling. Mechanical sticking is connected with key seating, formation-related wellbore instability, wellbore geometry (deviation and ledges), inadequate hole cleaning, junk in hole, collapsed casing, and cement related problems. Stuck pipe risk could be minimized by using available methodologies for stuck pipe prediction and avoiding based on available drilling parameters.

A Practical Study of the Influence of Drill Solids on the Corrosion of Downhole Tubulars When Using Brine Based Drilling Fluids

2021 ◽  
Author(s):  
Garett Heath ◽  
Temi Okesanya ◽  
Simon Levey
Keyword(s):  
Oxygen Content ◽  
Field Data ◽  
Drill Pipe ◽  
American Petroleum Institute ◽  
Filter Press ◽  
Drilling Fluids ◽  
Chemical Additives ◽  
Active System ◽  
Corrosion Rates ◽  
Fluid Properties

Abstract The proliferation of highly concentrated brine drilling fluids systems due to their enhanced performance benefits has instigated a plethora of technical studies on the mechanisms and control of their induced corrosion on downhole drilling tools and tubulars. The majority of these studies often overlook the effect of drill solids on corrosion rates. Therefore, a pragmatic and experimental study was conducted to investigate the effects of various factors on the corrosion rates of downhole tubulars with a streamlined focus on the obscure role of the understudied drill solids; which have not been fully elucidated. Drill pipe corrosion coupons and drilling fluids/solids obtained from 5 similar wells (located in Grande Prairie, Alberta, Canada) were utilized for experimental analysis. Wells 1 to 4 were on the same pad (surface drilling location) drilling the same formation with the same fluid properties, while the 5th well was on a different pad but drilled the same formation with the same fluid properties to exclude disparity. Industry-standard measurement was carried out on the live used corrosion coupon rings, drilling fluids and solids obtained from these wells to determine selected properties. The total solids content analysis was carried out using an OFITE API (American Petroleum Institute) filter press. Weight loss tests on drill pipe corrosion coupons were used to determine field corrosion rates which were bolstered with the Parr Hastelloy autoclave test in the Laboratory. The oxygen content was monitored using Hach 2100Q dissolved oxygen meter. Field data, images and experimental results showed that a rapid and minuscule increase of drill solids (as little as 1% v/v) in the active system can impact corrosion rates greater than chemical additives and even oxygen content. It was discovered that low concentration of solids can produce significant damage and a high corrosion potential in non-viscosified fluids thereby making live monitoring of drilling fluids’ properties a priority to mitigate corrosion. This study fills an important technical gap in corrosion study that is indispensable for the optimization of corrosion control in drilling operations. By carrying out a controlled and investigative study backed up with drilling field data and images, the effects of the less understood drill solids have been partially demystified.

A New Technique to Determine the Equivalent Viscosity of Drilling Fluids Under High Temperatures and Pressures

1970 ◽  
Vol 10 (01) ◽  
pp. 33-40 ◽  
Author(s):  
B.K. Sinha
Keyword(s):  
High Temperatures ◽  
Low Temperatures ◽  
Relative Viscosity ◽  
Test Fluid ◽  
Drilling Fluids ◽  
Sample Container ◽  
Invert Emulsion ◽  
Temperature And Pressure ◽  
Water Base ◽  
Time Required

Abstract Knowledge concerning the behavior of drilling fluids under wellbore conditions is very desirable, and experimental results have shown that the extent to which the flow properties of drilling fluids are affected by high temperatures and pressures cannot be predicted by standard API pressures cannot be predicted by standard API tests. A Fann consistometer (Model 5S-TDL) is modified to obtain the experimental data reported in this study. Data obtained from the Fann viscometer Model 50 at elevated temperatures have been included to supplement the information derived from the modified Fann consistometer. Newtonian fluids of known viscosities are used in calibrating the modified consistometer. The technique followed here keeps the sample temperature constant and allows the pressure to vary at each desired temperature level. The equivalent viscosities of both laboratory-prepared and field muds of different densities have been obtained at temperatures up to 500 deg F and pressures up to 20,000 psi. The objective of this study is to show that the modified consistometer can give much more information concerning the flow behavior of muds under wellbore conditions than that derived in the past. It can show the pressure and temperature conditions under which the tendency to thicken begins, the gradual thickening, and also the conditions at which the mud completely gels and loses its fluidity. The study shows that both temperature and pressure affect the equivalent viscosity of invert pressure affect the equivalent viscosity of invert emulsion muds. The effect of pressure is very pronounced at low temperatures. Compared to the pronounced at low temperatures. Compared to the invert emulsion muds, the equivalent viscosity of water base muds is not affected to the same extent by temperature and pressure. Temperature is the dominating variable tin case of water base muds. However, the effect of pressure on the equivalent viscosity of water base muds seems to depend on composition and temperature of the system. Introduction Kennedy and Crawford designed and patented the consistometer to test the setting time of cement slurries. This consistometer as manufactured and later improved by Fann. Chisholm et al. adapted the first Fann consistometer for evaluating drilling fluids under wellbore conditions in 1961; their study was later continued by Cox and Pfleger. Weintritt and Hughes used a similar consistometer with a different recording device. They measured the relative viscosity of drilling fluids in seconds and pointed out the usefulness of this data when used with viscometric and fluid loss data. They applied the term "relative viscosity" to the time required for the bob to complete movement in one direction: it is not a ratio of two viscosities. In spite of its wide usage, no standard testing procedure has been established by the industry to procedure has been established by the industry to obtain correlative data. A consistometer similar to the ones mentioned above, has been further modified and used in this study along the Fann viscometer Model 50. EQUIPMENT AND CALIBRATION Fig.1 is a section diagram of the consistometer. The consistency or equivalent viscosity of a test fluid is measured by electrically timing the movement of a soft iron bob that is magnetically pulled up and down in the sample container. Sound pulled up and down in the sample container. Sound signals created by the impingement of the bob inside the container are picked up by a microphone and transmitted to a recorder. The time required to pull the bob through a test fluid is a function of its pull the bob through a test fluid is a function of its consistency. The test fluid can be subjected to pressures up to 20,000 psi and temperatures up pressures up to 20,000 psi and temperatures up to 500 deg F. SPEJ p. 33

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