Cutting generated while drilling will increase drilling fluid density and it will finally affect equivalent circulating density while drilling. In this topic, we will talk about how to determine mud weight increase due to cutting.
Figure 1 – Cutting Increases Mud Density
Effective mud density due to cuttings in the hole can be determined by the empirical equation below;
This article is a summary of how to free stuck pipe caused by three main mechanisms which are wellbore geometry, differential sticking and packing/bridging off. It will give you some ideas which you can apply for your operation.
Free Stuck Pipe Caused By Wellbore Geometry
These following instructions are guide lines on how to free the stuck drill string caused by wellbore geometry.
What should you do to free the stuck pipe caused by wellbore geometry ?
• If the drill string gets stuck while moving up, jar down with maximum trip load and torque can be applied into drill string while jarring down. Be caution while applying torque, do not exceed make up torque.
• On the other hand, if the drill string gets stuck while moving down, jar up with maximum trip load. DO NOT apply torque in the drill string while jarring up.
• Flow rate must be reduced while attempting to free the drill string. Do not use high flow rate because it will make the stuck situation became worse and you will not be able to free the pipe forever.
We have created a simple table to help people determine the buoyancy factor quickly. Let’s take a look at the table. In Figure 1, it shows the main page and you can select the mud weight range from 4.0 ppg to 19.0 ppg.
Figure 1- Main Page BF Table
For instant, we choose 8.0 ppg and the table will show buoyancy from 8.0 – 8.9 ppg (Figure 2)
Blow Out Preventer is one of the most critical equipment on the rig therefore it is very important that you need to understand it. This VDO demonstrates the basic of BOP with a lot of colorful pictures which will help you learn about it. We also add full VDO transcript in order to help people fully understand this topic. We wish you would love this.
Full VDO Transcript Deails
The blowout preventer, BOP stack, consists of several large valves stacked on top of each other. These large valves are called blowout preventers. Manufacturers rate BOP stacks to work against pressures as low as 2m000 pounds per square inch or psi and as high as 15,000 psi. That is about 14,000 kPa to over 100,000 kPa.
Rigs usually have two kinds of preventers, on top is an annular preventer it is called an annular preventer because it surrounds the top of the well bore in the shape of a ring or an annulus. Below the annular preventer are ram preventers. The shutoff valves in RAM preventers close my forcing or ramming themselves together.
The choke line is a line through which well fluids flow through the choke manifold when the preventers are closed. Even though the preventers shut in the well the core members must have a way to remove or circulate the kick in the mud out of the well. When the BOP shut in the well, mud and formation fluids exit through the choke line to the choke manifold. The manifold is made up of special piping and valves. The most important valve is the choke.
As you know, we’ve always been trained or told to minimize influx (kick). Nowadays, there are several tools and procedures guiding us to prevent large influx; however, interestingly there are quite a lot of people who don’t understand why we need to do this. In this topic, we will demonstrate how kick volume will affect wellbore and surface casing pressure.
Main concept of minimizing kick coming into the wellbore is to minimize surface casing pressure when shut in. If you have excessive surface casing pressure, you will have a chance to fracture the weakest formation in the wellbore such as formation at casing shoe. You need to remember that more influx equals to more surface pressure. We will do basic calculation to see the effect of kick volume and surface pressure.
There are several API types of ring gaskets used in BOP connections and this is very important to personnel involving in drilling operation to know about it. API 6A: Specification for Wellhead and Christmas Tree Equipment is the standard which every manufacture refers to their equipment.
API Type R Ring Gasket
The API type “R” rig gasket is not a pressure energized gasket therefore this type does NOT recommend for BOP equipment or safety critical equipment as x-mas tree, wellhead valves, etc. Sealing area is along small bands of contact between the gasket and the ring gasket on both ID and OD of the gasket. Shape of type “R” may be oval or octagonal in cross section (see Figure 1). Additionally, face to face between flanges will not touch when the flanges are tightened (see Figure 2). The “R” gasket is compatible for 6B flanges.
As you know well control is very important subject in drilling industry and in order to understand it clearly, you need to understand basic principle. This time we would like to share this excellent VDO showing the basic pressure control of drilling process. It is just only five minutes but it will give you details plus illustration for more understanding. Additionally, we also add full VDO transcript for anyone who cannot catch the VDO content.
This is the VDO transcript from our team.
Fluids in a formation are under pressure. When drilled, this pressure can escape to the surface if it is not controlled. Normally, drilling mud offsets formation pressure, that is the weight or pressure of the drilling mud keeps fluids in the formation from coming to the surface.
We create a FREEandroid application showing several awesome background images in oilfield theme. There are a lot of beautiful pictures as drilling rig (land, jack up,semi, tender), pump jack, platform, etc. All images are in good quality.
Many people ask us a lot of questions regarding shoe pressure while circulating kick (wellbore influx) out of the wellbore. We will summarize all the scenarios to help you get clearer picture. There are a total of three cases which we will separately discuss as per the details below.
Note:All the calculations and scenarios are based on water based mud and gas kick.
First Scenario – Top of Gas Kick Below Casing Shoe
People asked me about what the closing ratio is and what it tells us. Closing ratio is defined as the cross sectional area of the ram piston (cylinder) divided by the cross sectional area of the ram shaft. The closing ratio is used to determine Ram closing pressure which will overcome wellbore pressure acting to Ram body.
Closing Ratio = Ram Piston Area ÷ Ram Shaft Area
Before going into the detailed calculation, we would like to show you where the cylinder and the ram shaft are in BOP. In Figure 1, the yellow shaded parts demonstrate these two areas which will be used to calculate the closing ratio.