Hydrocarbons occupy a vital role in our life and continue to play an important role for many more years to come. We need to follow all technological innovations to continue our productivity standards to achieve our production targets. Let us extend our vision to achieve this mission.

Thursday, August 23, 2012

Cutting Carrying Index – Simple Tool To Determine Hole Cleaning

To get the good idea on how good of the hole cleaning is, the another method called Cutting Carrying Index (CCI) is utilized. The CCI is an empirical relationship from real data and the equation is below:

Where;

AV is annular velocity in ft/min.

MW is mud weight in ppg.

K is a Power Law Constant.

The Power Law constant (K) can be calculated from the equation below:

Where;

PV is plastic viscosity in centipoises.

YP is yield point in lb/100sqft

n is flow behavior index.

The flow behavior index (n) can be determined by the following equation:

Where;

PV is plastic viscosity in centipoises.

YP is yield point in lb/100sqft

How will the CCI tell you about hole cleaning?

If CCI is equal to 0.5 or less, the hole cleaning is poor and the hole problem may be seen.

If CCI is equal to 1.0 or greater, it indicates that the hole cleaning is good.

Please follow the example to determine CCI.

Mud Weight = 9.2 ppg

Annular Velocity = 140 ft/min

Plastic viscosity = 17 cp

Yield Point = 15 lbs/100 sq ft

Determine "n"

n= 0.61472

Determine "K"

K = 353.71

CCI=(353.71(140)(9.2))/400,00

CCI = 1.14

From the given drilling parameters, the hole cleaning is excellent.

Careers in the Oil and Gas Industry





This document is not an all inclusive document. The purpose is to give the reader a general overview of what jobs are available.


DOWNLOAD



Created and shared by: Williston Job Service
Edited By: Sidney Job Service

Thursday, August 16, 2012

August 2012 issue OFFSHORE Magazibne


 

Offshore
The August 2012 issue of Offshore is available to
view or download.

Feature Articles


Departments
Online Vessels, Rigs, & Surface Systems
Comment Drilling & Production
Data Geosciences
Global E&P Offshore Automation Solutions
Offshore Europe Business Briefs
Gulf of Mexico Advertisers' Index
Subsea Systems Beyond the Horizon


Other resources available from PennWell

Offshore Maps & Posters
PennEnergy.com Research and Data
PennWell Books Spring 2012 Energy Catalog



For DOWNLOAD INSTRUCTIONS: http://www.qmags.com/DownloadingHelp.asp

To reach our HELP DESK, please visit: http://www.qMags.com/help



To view the archived files on your Qmags account, please click here.
Recent issues you have not yet read
June 2012

June 2012

July 2012

July 2012


.



Thursday, August 9, 2012

Mud Up Calendar Rotational Planner Sheet for Oilfield Personnel

My friend sent me the rotational planner sheet few day ago and I think this is really handy for someone who work as rotational schedule. It helps me save a lot of time trying to mark my working schedule on the calendar.

my time off

Please find the excel sheet here >Rotational Planner Sheet for Oilfield Personnel

How to use it?

1. Open the rotational planner sheet. You will see the excel sheet look like this.

2. At the top left of the sheet, select the year. This year is 2011 so I put 2011 in this box.

3. Select time off. For example, if I am off the rig on 25-Jan-11, I select the 25 January 2011.

4. Select work schedule. Each number means time on and time off. For example, 7 means work 7 days and off 7 days. For me, I select 28.

5. Your work schedule is ready. The green cell is when you start your time off and the red cell is time when you start working. Moreover, the blue-shaded cells are your time off and the white cells are your working time.

Note: this sheet works only for even time on and time off. You cannot use it if your schedule is not even. For instant, if your work schedule is 4 week on and 2 week off, you will not be able to use it.

Thanks PeteHeff for creating this useful excel sheet.

Natural Gas to Provide Bulk of New Capacity


Source: Mavis Scanlon, Energy Prospects West  (8/8/12)

"North America could see 112 GW of new renewable-energy capacity by 2037, but the continent could see more than three times as much new capacity from natural gas-fueled generation over the same period."


North America could see 112 GW of new renewable-energy capacity by 2037, driven in part by state renewable portfolio standards, but the continent could see more than three times as much new capacity from natural gas-fueled generation over the same period.

That's according to the midyear Energy Market Perspective report from engineering and consulting firm Black & Veatch. The 2012 midyear update reflects a more rapid shift to gas than was anticipated just last year, Black & Veatch executives said at an Aug. 1 press breakfast to discuss the company's findings.

The development of shale-gas resources—the Energy Information Administration estimates U.S. recoverable gas resources exceed 2,200 Tcf, a 90-year supply—has led to expectations of low gas prices for years to come.

Just a few years ago, no one foresaw gas prices under $3/MMBtu, said John Chevrette, president of management consulting at Black & Veatch. That "has led to a fundamental shift in the way [utilities] think about generation," he said.

Low gas prices coupled with U.S. Environmental Protection Agency regulations aiming to reduce criteria air pollutants are drivers for expected coal-plant retirements in coming years. Black & Veatch expects 61.5 GW of coal-plant retirements by 2020; that forecast does not include expected retirements driven by potential greenhouse-gas emissions regulations, the report noted.

Renewables will help close the gap, although Black & Veatch expects most new generation in coming years to be gas-fired.

"When it comes to new generation it's going to be gas," said Dean Oskvig, president and CEO of Black & Veatch's global energy business.

Natural gas now accounts for about 35.9% of U.S. generation capacity, with conventional coal accounting for about 29.6 percent. By 2037, Black & Veatch expects natural gas generation to top 55%, with conventional coal generation dropping to 13.3% of the capacity mix.

Black & Veatch projects gas demand from the power sector to grow about 2% a year, translating to more than 380,000 MW of new capacity before 2037. That is 27% higher than the company's previous forecast.

Renewables, mostly wind, will also play a role. The midyear report forecasts renewables capacity to grow to 182,833 MW, or about 13.3% of U.S. capacity mix, in 2037, up from 70,588 MW, or about 6.6%, in 2013.

In planning for larger amounts of intermittent renewables capacity on the grid, a lot of focus has been on ensuring the availability of backup generation needed during peak periods. But another big question looming for the power sector is how to handle large amounts of renewables during periods of low loads. In spring months, when it is windy and when hydroelectric generation is high due to runoff, where does excess power go?

"Nuclear plants can't ramp down," said Ryan Pletka, director of renewable energy strategic planning at Black & Veatch.

Indeed, the way the grid was developed, in a balkanized fashion, has hindered the ability to move power from region to region, Oskvig said. "We can avoid building a lot of new generation if we could use what we have more economically."

The company expects nuclear capacity to drop as a percentage of the country's overall capacity mix by 2037. Nuclear capacity two decades out is forecast to be 79,911 MW, or about 5.8% of capacity mix, compared with 102,576 MW, or 9.6%, in 2013, the report states.

The economy and low gas prices have both helped slow nuclear development, the company said. The heavy capital costs involved in building new nukes mean that only the largest utilities with healthy balance sheets can take on the expense. At a capital cost of $7 to $8 per kW, "one project might be a utility's whole balance sheet," Oskvig said. It takes a Southern Co., Duke Energy, Entergy or PG&E Corp. to do that, he added.

That means "relicensing the existing fleet becomes more critical," Chevrette said. "We're probably not going to build as many nuclear plants."

Mavis Scanlon
Energy Prospects West

Prevention of Stuck Pipe During Routine Operations

Reaming is a high risk operation which accounts for a large proportion of stuck pipe incidents. If reaming operations are conducted too fast solids from wash-outs and cavings are introduced into the circulating system at a faster rate than the hole is being cleaned. This results in a pack-off. Do not assume that any resistance is always at the bit; stabilisers and drill collar contact may be indicative of a build up of loose material in the hole and a potential pack-off situation. The following guidelines are offered as a general list.

stuck pipe prevention

Stuck pipe prevention

Planning


a1. Have a contingency plan for all possible problems. E.g., what to do in case of a leaking swivel packing or leaking saver sub.

a2. Always pre-plan a trip. Have an up-to-date mudlog on the rig floor. Know where high doglegs exist and note troublesome areas from past trips. Utilise the mud loggers' paper model of the BHA and well bore previously mentioned.

a3. Have singles in the V-door in case downward motion is required to free the pipe after a connection.


Organisation

b1. The shakers must be monitored continuously and the volume of solids being removed from the well bore should be recorded.

b2. While drilling or reaming in problem formations have two people at the console: one man on the brake and the other on the pumps.

b3. Ensure that the driller knows what actions to take in the event of problems. Are overpull limits, freeing procedures and reaming practices understood? Are written instructions for the driller prepared and updated regularly?

b4. Mud loggers will record all parameters. Significant changes in trends should be reported immediately to the driller and BP rig supervisor, then investigated.


Parameters

c1. Use consistent parameters for reaming operations. This assists in identification of changes in torque and pressure trends.

c2. Any indication of changes in parameters should be addressed immediately. Most drag problems can be reduced by time spent circulating the hole clean.

c3. An increase in drag, torque or pressure may indicate that the annulus is loaded up, and a pack-off may be forming. Circulate and clean the well bore before continuing reaming.

c4. If indications of a pack-off occur, immediately reduce the pump strokes (e.g. by half ) to reduce the pistoning effect. If, after several minutes the hole does not pack-off, return to the original parameters and be prepared to circulate the hole clean.

c5. Reaming speed and circulation time should be adjusted if the returning cuttings' volume rate is excessive.

c6. If torque becomes erratic or any of the following occurs: a) The rotary is stalling out. b) The cave-in rate increases.
c) Torque and pressure readings are increasing, then be prepared to stop, circulate and clean up the hole.

c7. Prior to heavy reaming, slow rotation ( c8. Reaming operations should be conducted with the same flow rate as drilling.

c9. Reaming weight and speed should be kept low (< 10 – 15k lbs either up or down). This reduces the chance of sidetracking the well and is less damaging to the drill string.

c10. Control the speed of reaming operations (4 stands an hour can be used as a rule of thumb for the maximum speed). This should also reduce the mechanical damage the drill string does to the well bore.

c11. Large volumes of settled cuttings or new cavings can be introduced to the hole when reaming. It is critical that this material is circulated out of the hole.


General/Operation

d1. If the hole packs-off, immediately shut down the pumps and slowly bleed the pressure under the pack-off down to less than 500 psi.

d2. While reaming in problem formations the hole may need to be wiped at regular intervals, if conditions require it.

d3. Do not use the Soft Torque while reaming as it may disguise torque trends.

d4. Make sure the pipe is free before setting the slips.

d5. After drilling or reaming down, the cuttings should be circulated above the BHA prior to picking up.

d6. The preferred practice is to always try to work the string past a tight spot as a first option. However, overpull limits must be known and used. Work up to the overpull limit in stages ensuring free movement in the other direction at each stage.

d7. Limiting overpulls to half the BHA weight has proven to be a successful strategy in avoiding stuck pipe.

d8. If the top drive stalls out during reaming operations there is a great deal of stored energy in the torqued up drill string, always release this torque slowly.

d9. When back-reaming do not overpull the pipe into the slips to connect the top drive.

d10. When washing in, with a motor in the BHA, rotate the whole drill string at low rpm.

<iframe width="420" height="315" src="http://www.youtube.com/embed/Zshp1MkS0XQ" frameborder="0" allowfullscreen></iframe>


How to Identify Stuck Pipe Mechanism

When a stuck pipe situation is happened, personnel on the rig must correctly identify a stuck pipe mechanism.

Why is it so important to determine the mechanism of stuck pipe?

If you know cause of stuck pipe, you will be able to free you pipe correctly. However, if you cannot correctly identify a root cause of stuck pipe, you drill string may be in the hole forever!!!

Many people in the oil field including me use the guideline from the famous stuck pipe prevention book, named "TRUE", which is belong to Amoco. It is extremely useful and so easy to understand.

This is the stuck pipe table.

How can you use the table?

1. Select the situations that you see and circle all the figures in the same row.

2. Add all figures for each column

3. The highest score indicates the stuck pipe mechanism

Let's see the example

Pipe motion prior to sticking? – The pip can be moved down before sticking = Move down (1, 0, 2)

Pipe motion after sticking? – The pipe has restriction while moving down= Down Restricted (1, 0, 2)

Pipe rotation after sticking? – The pipe can be rotated freely after sticking = Rotate Free (0, 0, 2)

Circulating pressure after sticking? – The circulation can be done without any pressure changes = Circulation Free (0, 2, 2)

Total score = (2,2,8)

The highest score is wellbore geometry; therefore, the most likely possible mechanism of stuck pipe is wellbore geometry.

Drilling formulas Stuck Pipe Prevention Book => Stuck Pipe Prevention Book  Stuck Pipe Prevention Book

Calculate Bottles Required for Koomey Unit (Accumulator Unit)

This topic will demonstrate you how to determine accumulator bottles required for Koomey Unit (Accumulator Unit) in order to close the BOP stack.

This is a specification of Accumulator (Koomey) Unit.

Accumulator 3,000 psi system

Volume each bottle is 10 gallon.

Pre charge pressure is 1,000 psi.

Minimum operating pressure is 1,200 psi (200 psi over pre charge pressure)

Usable fluid per gallon is 5 gallon.

Safety factor require is 50 %.

 

BOP Stack and HCR's as listed below:

 Equipment  Gallon to open  Gallon to close
 Annular Preventor  4.0  4.5
 Upper Pipe Rams  3.0  3.5
 Blind Shear Rams  3.5  4.0
 Lower Pipe Rams  3.0  3.5
 Choke HCR  0.5  0.5
 Kill HCR  0.5  0.5

Please follow the steps below for calculation

 1. Determine total volume require to close all of equipment

Volume = 4.5+3.5+4+3.5+0.5+0.5 = 16.5 gallon

2. Volume accounted for safety factor

Volume = 16.5 x 1.5 = 24.75 gallon

3. Determine numbers of accumulator bottles required to meet volume determined in step#2

Number of bottles = volume ÷ usable fluid per bottle

Number of bottles =24.75 ÷ 5 = 4.95 so you round it up to 5 bottles

In order to close all BOP as per requirement without any assistance of electric and pneumatic pumps, you need to have a total of 5 accumulator bottles.

You will see that based on the calculation above, determining required Koomey bottles is quite straight forward. Thing to remember is that you must use closing volume not opening volume. I see many people using the wrong figures. Even though it may not have big impact on the final result, you need to select the right figures for calculation. Moreover, the safety factor may be different based on the regulations of your working area or your company policy.

Diverter Systems In Well Control

The diverter is an annular preventer with a large piping system underneath. It is utilized to divert the kick from the rig and it can be used when the conductor pipe is set. It is not used if you drill riserless. The large diameter pipe typically has two directions diverting the wellbore fluid out of the rig (see the figure below for more understanding).

The diverter should be used only when the well cannot be shut in because of fear of formation breakdown or lost circulation. Use of the diverter depends on the regulations and operator policies.

The diverter is normally installed on a conductor casing with large diverter pipe pointing to a downwind area. Typically, the selective valves located at each diverter line can be operated separately so the personnel on the rig can divert the flow into the proper direction. It is designed for short periods of high flow rate but it cannot hold a lot of pressure. With high flow rate, the erosion can be happened easily so the bigger of diverter line the better. Additionally, the straight diverter lines are the most preferable.

In the market, there are several models provided by service providers as

Hydril Pressure Control FSP* 28-2000 Diverter

http://www.ge-energy.com/products_and_services/products/capital_drilling_equipment/hpc_fsp_28_2000_diverter.jsp

Hydril Pressure Control FS™ 21″ 500-psi Marine Riser Diverter

 

http://hydrilpressurecontrol.com/pressureControl/diverters/diverters-FS.php


Reliance Industries cuts KG-D6 gas field reserves by 70 pc

Reliance Industries has slashed natural gas reserves in its main production gas fields in the Krishna Godavari basin D6 block by 70 per cent to 3.10 Trillion cubic feet (Tcf) due to "unforeseen geological surprises".

Minister of State for Petroleum and Natural Gas R P N Singh told the Lok Sabha in a written reply that RIL had estimated 10.3 Tcf of recoverable reserves in the Dhirubhai-1 and 3 (D1&D3) gas field in the KG-D6 block.

"Subsequently, the contractor (RIL) revised the estimates of recoverable reserves of D1&D3 fields as 3.10 Tcf," he said.

D1&D3, the biggest of the 18 finds RIL has made in the deep-sea block in Bay of Bengal, had begun production in April 2009 and had produced 2 Tcf of gas during past three years.

MA oilfield in the same KG-D6 block was estimated to hold 681.4 Billion cubic feet (Bcf) of recoverable gas reserves and RIL has now revised the numbers to 788 Bcf, he said.

Singh said the block KG-DWN-98/3 or KG-D6 produced 15.106 bcm of gas in 2009-10 which rose to 20.4 bcm in 2010-11. But in the subsequent year, it fell to 15.611 bcm.

The fall in output was because one-third of the 18 gas producer wells in D1&D3 fields "ceased to produce gas due to water/sand ingress in well bores," he said, adding on MA field, two of the six wells had ceased due to same reasons.

"The operator (RIL) has attributed lower gas production as compared to approved plan from D1&D3 fields to unforeseen geological surprises and reservoir," Singh said.

The Directorate General of Hydrocarbon has attributed the fall in output to "non-drilling of the required number of gas producer wells in D1&D3 fields by the contract in line with the Addendum to Initial Development Plan (AIDP)," he said.

In the AIDP, RIL had committed to drill 31 wells and produce 80 million standard cubic meters per day of gas by this time of the year. But, output is currently less than 29 mmscmd.

Wednesday, August 8, 2012

Advances in high-performance drilling fluids

Advances in high-performance drilling fluids enhance wellbore strength, help curb loss

By Maggie Cox, editorial coordinator

Two M-I SWACO drilling fluid specialists monitor drilling fluid returns from the shaker that separates the fluid from the drill cuttings.

Two M-I SWACO drilling fluid specialists monitor drilling fluid returns from the shaker that separates the fluid from the drill cuttings.

Operators and service companies are developing new advances in high-performance drilling fluids and techniques in order to enhance wellbore strength and mitigate difficult-to-drill areas like shale plays, deepwater and HPHT wells.

The industry has evolved to be able to tackle hotter, higher-pressure wells and thousands-of-feet deep extended-reach wells while easy-to-reach resources are being depleted.

"There are new technical challenges because the easy oil is already being produced. It's the tough oil we're going after now," Jim Friedheim, director of corporate fluids research and development, M-I SWACO, said.

In response, drilling fluid teams throughout the industry have developed high-performance drilling fluids to meet environmental regulations while utilizing wellbore-strengthening techniques to preserve the well.

"Wellbore-strengthening techniques are most effective when they are preventative techniques, in that you have to do something to the wellbore before you have bad losses," Dave Beardmore, drilling fluids specialist, ConocoPhillips, said.

By strengthening the wellbore, the operator can limit the possibility for lost circulation, which can make drilling more efficient. Mr Beardmore suggested seven ways to increase wellbore strength (see sidebar). The most widely used method involves utilizing specially-sized granular additives, others include rigid-plug forming treatments, chemical sealants and low-fluid loss muds.

 A lab technician uses a Fann Thermo-cup to quickly heat drilling fluid samples to test the viscosity of the fluid.

A lab technician uses a Fann Thermo-cup to quickly heat drilling fluid samples to test the viscosity of the fluid.

Wellbore-strengthening techniques are similar to lost-circulation techniques, but there are significant differences. Strengthening techniques still focus on avoiding loss, but also on increasing the apparent fracture gradient by sealing the fracture and isolating the fracture tip to keep it from further elongating, while lost circulation only mitigates losses of whole mud.

M-I SWACO integrated borehole-strengthening solution (Figure 1) is an example of this technique.

In conjunction with the movement toward strengthening techniques, there has also been a greater emphasis on high-performance drilling fluids due to stricter environmental regulations and the increased cost of drilling. Operators want the drilling fluids they use to function like one of their tools to drill faster and better, Dr Friedheim said.

"Reliability is a key factor for the operators. They want a fluid that is reliable, and the more reliable fluids are oil-based or synthetic-based muds," he said.

Part of meeting regional environmental standards, especially in sensitive areas like the Arctic, has been to transform synthetic fluids with relatively higher toxicity into environmentally benign fluids.

This transition has been a challenge not only for drilling fluid teams but operators as well. Operators have to wait on new technology to be proven and tested before they can implement it on a rig.

"The biggest challenge we face is developing new products that maintain mud properties while making the mud benign to the environment," Mr Beardmore said.

Before low-toxicity synthetic fluids came to fruition, the industry was using cheaper and more damaging fluids, like diesel-based fluids. The fluids today are more costly but are efficient in meeting the needs of operators drilling complicated wells, Dr Friedheim said.

"We're in hostile environments now, and the fluids are expected to keep up with the demands," he added.

 A lab technician pours drilling fluid into a pressure cell for proper stirring with the Heidolph stirrer prior to viscosity testing.

A lab technician pours drilling fluid into a pressure cell for proper stirring with the Heidolph stirrer prior to viscosity testing.

MITIGATING THE VARIETY OF COMPLEX WELLS

Shales

High-pressure, high-temperature wells (HPHT), shales and depleted and underpressured zones are examples of trouble areas that have prompted the innovation of new drilling fluids and wellbore- strengthening techniques.

Shale zones pose a particular problem with water-based fluids. Sometimes, using water-based fluids leaves the operator with a little more than a week to get casing across the well.

According to Ben Bloys, team leader of the fluids and waste management technology group, Chevron, to keep a hole stable in the shale sections of wells, there especially needs to be mechanical help keep the soft shales sturdy, which means using the appropriate mud weight.

Chemical strength is another important part of keeping the hole stable, which requires maintaining the original rock strength for as long as possible. "There are a lot of stories about some shales staying stable for only taking seven days or so when being drilled with water-based mud. There are a dozen ways that water-based fluids interact with shales, and they all reduce the strength of the wellbore," Mr Bloys said.

However, not all shale plays in North America are the same, said Halliburton Baroid's director of technology, Nick Braley. "Once we started breaking into the shale play market, we quickly realized the shale plays of North America are very diverse and require a high degree of fluid system customization," he said. "There was no simple solution that you could introduce to all shales because they aren't all the same."

The company developed the SHALEDRIL family of water-based fluid systems designed specifically to meet challenges in the Haynesville, Fayetteville, Barnett and Marcellus shales. These customizable water-based muds help to combat high-temperature and acid gas in the Haynesville, shale delamination of smectite/chlorite mixed-layer clays in the Fayetteville, illitic clay cuttings and dispersion in the Barnett and shale disintegration in the Marcellus.

Halliburton deployed SHALEDRIL H for the first time earlier this year in a well in Louisiana. Currently the company is working on a water-based fluid solution to address challenges in the Eagle Ford Shale.

Two M-I SWACO drilling fluid specialists monitor the centrifuge system, part of the solids control systems used to keep the fluid clean.

Two M-I SWACO drilling fluid specialists monitor the centrifuge system, part of the solids control systems used to keep the fluid clean.

HPHT

Despite the many challenges of drilling in shale, in Mr Braley's opinion, HPHT wells have been the more difficult to mitigate. Keeping good fluid properties in high-temperature wells is not an easy task. "You have to keep fluid suspension characteristics so you don't have barite settlement. You can't afford to see the fluid break down or destabilize under high temperatures," he said.

Temperature change can make the drilling fluid too viscous or not viscous enough. "We've been trying to re-engineer liquid additives to be solid additives, which will still free flow at cold temperatures and maintain good fluid properties," Dr Friedheim said. Deepwater has given experts insight on how to develop this technology.

In deepwater, there are several thousands of feet of water where temperatures, depending on the region, can range from 34 – 40°F. In addition to these low temperatures, water currents must also be taken into consideration, which can act like a wind chill on land – making the temperature drop further. Fluids are thicker going down through the riser and change once meeting the hot wellbore, where it becomes thin, he said.

This environment allowed experts to test new technology, and in the last several years flat-rheology muds have provided a solid solution. These muds do not have as big a swing in viscosity and can withstand temperature changes throughout the drilling process.

For example, M-I SWACO flat-rheology mud, Rheliant, uses a synthetic-based fluid and specialized additives to minimize barite sag, pressure spikes and progressive gel strengths, which come in handy when encountering fluctuating equivalent circulating density (ECD) values.

Depleted reservoirs and underpressured zones

When it comes to drilling a depleted reservoir or underpressured zones, John Trenery, director of research and development for drilling fluids for Baker Hughes, believes using wellbore- strengthening techniques will alleviate potential problems.

Figure 1: The M-I SWACO integrated borehole strengthening system (I-BOSS) is considered a wellbore-strengthening technique. These three graphics show how this system works to plug up fractures and keep them from elongating further into the wellbore in order to prevent loss and increase circulation.

Figure 1: The M-I SWACO integrated borehole strengthening system (I-BOSS) is considered a wellbore-strengthening technique. These three graphics show how this system works to plug up fractures and keep them from elongating further into the wellbore in order to prevent loss and increase circulation.

"We will run our wellbore-strengthening technique and look at the reservoir, the underpressured zone, what the overbalance pressure is going to be and the porosity of the foundation, then model a bridging package that will help seal the zone," he said.

Using a product like Baker Hughes' MAX-BRIDGE in an area like a depleted reservoir can reduce pore pressure transmission and seal micro-fractures in shale and low-porosity sands. This bridging system consists of a deformable sealing polymer with graphite additives. It mitigates pipe sticking, downhole losses and torque and drag, and it's applicable in water-based and invert emulsion mud systems.

IS OIL OR WATER BETTER?

There are some advantages to using water-based fluids over oil-based. For instance, water-based fluids do not damage the reservoir as much nor do they leave behind fluid-coated cuttings for disposal like oil-based muds.

MAX-BRIDGE and SHALEDRIL are considered some of the advances in water-based fluids. However, with wells increasing in complexity, like with deviated wells and s-curve wells, using water-based muds can pose more of a challenge because it's not naturally lubricious. "We can add lubricants to water-based muds, but if you start out with something that's inherently lubricious, you've already dealt with one of the challenges," Halliburton's Mr Braley said.

Oil-based muds are readily lubricious and offer a faster rate of penetration (ROP) and a more stable wellbore by not soaking into the well's foundation. Synthetic fluids also do not produce hydrates like water-based muds, which can clog choke and kill lines, stalling drilling further.

Micronized barite is one of the recent major advances in synthetic fluids. When used in drilling fluids to increase density, using very finely-ground barite or other mineral weighting agents allows  lower rheological properties to be used, that result in lower annular pressure losses while not experiencing barite sag. This allows the operator to have a fluid with a much lower effective circulating density, ConocoPhillips' Mr Beardmore said.

This is a helpful tool when drilling a narrow pressure window or drilling complex, high-angle wells where barite sag or narrow annulus situations can lead to problems, he said.

Even diesel-based fluids have undergone a transformation into a more environmentally friendly fluid. Diesel-based fluids contain cyclic molecules that are complex and won't degrade. This is why most diesel muds are banned in many areas of the world.

However, Halliburton developed a fluid system called the INTEGRADE invert emulsion system, is a diesel-based fluid system that is organophilic clay-free and lignite free. Polymer technology replaced these elements, which has led to better ECD control when tripping in and out of the hole and less wellbore damage, Mr Braley said.

Cleaning up the cuttings

While there has been movement toward using low-toxicity synthetic fluids, cleaning up cuttings can get complicated depending on the region's disposal regulations.

"Years ago we just focused on aquatic toxicity. When the industry realized that there was more than just aquatic toxicity, they looked at things such as biodegradation and how long cuttings stayed in the ecosystem," Dr Friedheim said.

This resulted in more environmental regulations on waste-management disposal. Innovations such as M-I SWACO PARALAND, for instance, helps fluid-soaked cuttings degrade faster by formulating a drilling fluid using synthetic biodegradable base fluids, additives and a non-chloride internal phase, which can ameliorate some of the consequences of using synthetic fluids.

So which is better – water-based or oil-based? Both have pros and cons depending on the job.

According to Mr Beardmore, evaluating the complexity of the well can help determine what kind of fluid is best. "If you're drilling a simple well, you often shouldn't use an oil-based mud because it's more expensive, but if you're drilling a complex well, a synthetic fluid would likely be more cost-effective," he said.

Especially if the simple well in question has the potential to have a lot of loss circulation, replenishing the well with oil-based fluid versus water-based would be more expensive for the operator.

Completion fluids

Completion fluids have also advanced. For example, Halliburton's N-SOLATE, thermally insulating packer fluids solution, targets and controls heat transfer as oil is coming up the well. This helps improve production by keeping the oil from depositing asphaltenes in the production tube, which can impact production rates. This solution uses thermally activated polymer technology (TAPT) to control convection and conduction heat transfer in the well. Originally, the N-SOLATE system was aimed toward the offshore market to mitigate annular pressure buildup between the production casing and outer casing once the well has been put on production.

However, Halliburton had the opportunity to test its third version of the product (N-SOLATE 600) for a customer in the Middle East who was drilling steam-injection wells. Because the steam reached over 500°F, the customer saw an excessive amount of casing expansion.

By applying this packer fluid, the customer was able to reduce casing expansion by more than 50%. Halliburton now has two other opportunities to apply this packer fluid in Alaska and Russia, where permafrost melting is a consistent problem. "Once the technology came out, other opportunities became apparent. But when we were talking about developing a packer fluid, because of the terminology we used, people weren't thinking outside the box of where else this could be used," Mr Braley said.

These photos illustrate Baker Hughes' MAX-BRIDGE water-based drilling fluid system, which is comprised of MAX-SHIELD (lower left), LC-LUBE (lower right) and LC-LUBE Fine, which synergistically plug and seal pore throats and fractures in depleted sand and limestone formations. MAX-SHIELD helps seal micro-fractures in a Pierre II shale. This system is one of the advances in water-based fluid systems.

These photos illustrate Baker Hughes' MAX-BRIDGE water-based drilling fluid system, which is comprised of MAX-SHIELD (lower left), LC-LUBE (lower right) and LC-LUBE Fine, which synergistically plug and seal pore throats and fractures in depleted sand and limestone formations. MAX-SHIELD helps seal micro-fractures in a Pierre II shale. This system is one of the advances in water-based fluid systems.

ADVANCES IN MUD MONITORING

Thinking outside the box is always necessary when developing new technology. In addition to the developments that have been made to the fluids themselves, experts have come up with better mud-monitoring software to test wellbore strength and plan what kind of fluid to use.

"Wellbore-strengthening modeling has evolved more into a science than an art. A couple of years ago we didn't really have the tools to model wellbore strengthening, we only had a general concept, and that's what we're working on now," Baker Hughes' Mr Trenery said. "It's not 'one shoe fits everything.' It's customized techniques for given locations and wells."

In his opinion, modeling wellbore strengthening techniques allows the operator to be objective, safer and more efficient.

For example, Chevron currently has a study focusing on mud monitoring in shale areas. A joint project derived from the company's Tulsa University Center of Research Excellence and professor Mengjiao Yu. The duo has worked to pinpoint what elements are needed to keep shale wells stable when using water-based muds. Dr Yu has created a modeling system that, with a few well parameters or cutting samples, can determine everything from the effects of temperature on shale, to how much salt you need to put into the drilling fluid to keep the shale from collapsing. His modeling system can also estimate how quickly strength will be lost and how the operator needs to respond. The wellbore stability model is able to take into account multiple solutes, as well as key parameters such as initial rock strength, pore pressure changes, temperature, and time, Mr Bloys said.

Halliburton is also working on automated mud-monitoring equipment and the introduction of its real-time engineering software which focuses on hole cleaning and ECD management. Working with Sperry's INSITE software, the company has been able to transmit real-time drilling data from the rig and incorporate it into the model. "When we first rolled it out, it was really exciting, but we quickly identified that a major limitation we had was that the actual drilling fluid testing information around rheology and density weren't in real time," Mr Braley said.

Since then, the company developed a real-time density and viscosity meter, which was able to be implemented in field tests in about a six-month window. This tool allows fluid properties to be checked continuously on approximately a 30-minute cycle, which Mr Braley said keeps his engineers free to analyze data and optimize performance. "For me the benefit of this technology is freeing up time so the drilling fluids engineer can actually engineer and have to time analyze the results rather than being in a sort of 'testing only' mode. It's about increasing efficiency and effectiveness of our people."

7 ways to strengthen your wellbore

1) Putting Granular loss-circulation materials in the mud before can help stop up fractures in the foundation, preventing loss. This includes materials like ground-up rock, nuts and paper.

2) Using high fluid loss slurry when you have lost circulation into a fracture, the slurry loses all of its liquid to the formation and leaves behind solids to plug the fracture and prevent losses.

3) Chemical sealant is like an epoxy that is pumped into the wellbore that leaks into the formation and then set up in the pore space and prevent losses.

4) Heating the wellbore will make it stronger. If you heat the rock around the wellbore, it's going to try and expand, so it increases rock stress, which makes it harder to break down.

5) Smear effect – This happens when drilling with casing. The pipe smears the cuttings and filter cake into the wall, creating a plaster-like sealant that keeps the wellbore from breaking down.

6) Rigid-plug forming treatment are liquids that, when mixed, transform into cross-linked polymers, latex rubber, cement, etc, that set up in the fractures of a well to prevent lost circulation.

7) Ultra-low fluid loss muds are used to mitigate losses in permeable formations. By putting things in the mud that reduce the initial spurt loss of mud into the formation, that make the filter cake nearly impermeable and the wellbore is less likely to break down.

* Information provided by Dave Beardmore, ConocoPhillips.

ON THE HORIZON

Where is the industry headed now? ConocoPhillips' Dave Beardmore hopes the industry will create better high-temperature systems and high-performance water-based muds. "It is the 'holy grail' of the industry to find a water-based mud that drills like an oil-based mud," he said. This, he believes will continue to be a challenge for industry experts.

Of course, as one process of development ends, another one begins and shows the true cyclical nature of this industry. "We continue to look for new solutions. Now we're getting back into that circle of how do we break down the new systems that we've made to survive in HPHT wells and clean them up and remediate them," Mr Braley said.

Thursday, August 2, 2012

What is Tertiary Well Control?

Can you imagine if primary and secondary well control are failed?

Well is flowing all the time so how can we deal with this situation?

For this situation, you must use Tertiary Well Control.

Tertiary Well Control is specific method used to control well in case of failure of primary and secondary well control. These following examples are tertiary well control:

    • Drill relief wells to hit adjacent well that is flowing and kill the well with heavy mud. Note: this case you can study from PTTEP Austraila Blow Out Incident. They use this method to control the well that was firing on the platform.
    • Dynamic kill by rapidly pumping of heavy mud to control well with Equivalent Circulating Density (ECD)
    • Pump barite or gunk to plug wellbore to stop flowing
    • Pump cement to plug wellbore

What is Secondary Well Control?

Referring to the previous section, primary well control is hydrostatic pressure bore that prevents reservoir influx while performing drilling operations (drilling, tripping, running casing/completion, etc). When primary well control is failed, it causes kick (wellbore influx) coming into wellbore. Therefore, this situation needs special equipment which is called "Blow Out Preventer" or BOP to control kick.

BOP - Blow Out Preventer

Well, we can call that "Blow Out Preventer" or BOP is Secondary Well Control. Please also remember that BOP must be used with specific procedures to control kick such as driller method, wait and weight, lubricate and bleed and bull heading. Without well control practices for using BOP's, it will just be only heavy equipment on the rig.

There are several types of "Blow Out Preventer" (BOP) which have different applications. I will talk about BOP categories later.

What is Primary Well Control?

Primary Well Control is hydrostatic pressure provided by drilling fluid more than formation pressure but less than fracture gradient while drilling. If hydrostatic pressure is less than reservoir pressure, reservoir fluid may influx into wellbore. This situation is called "Loss Primary Well Control".

Not only is hydrostatic pressure more than formation pressure, but also hydrostatic pressure must not exceed fracture gradient. If your mud in hole is too heavy causing broken wellbore, you will face with loss circulation problem (may be partially lost or total lost circulation). When fluid is losing into formation, mud level in well bore will be decreased that will result in reducing hydrostatic pressure. In worst case scenario, you will lose the primary well control and wellbore influx or kill will enter into wellbore.

Typically, slightly overbalance of hydrostatic pressure over reservoir pressure is normally desired. You must keep in mind about the basic of maintaining primary well control that you must maintain hole with drilling fluid that will be heavy enough to overbalance formation pressure but not fracture formation.

Wild Well Control’s Technical Data Book

This is a very good book for well control "Wild Well Control's Technical Data Book" which is a quick reference book of formulas, charts and tables.

Wild Well Control Technical Book Wild Well Control Technical Book

I've found that it is very useful because it contains a lot of useful information as formulas, table, technical specification, etc.

You can download this electronic version by clicking the following link.

News Today - 2 Aug 2012



 

1. News on Oil Prices

 

2 August 2012 : Brent oil supply drop in Sept threatens price spike  {Reuters}


A drop in supply of crude that underpins the Brent crude contract in September has the potential to boost prices, further . . .

 

2 August 2012 : Oil cos hike jet fuel prices by 4.5%  {thehindubusinessline.com}


With firming up of oil prices in the international market, jet fuel or aviation turbine fuel prices were today hiked by 4.5 per cent, the second . . .

 

2 August 2012 : Asim supports call for reversing oil price hike  {dawn.com}


Severely criticising the increase in prices of petroleum products, the standing committee of the National Assembly on petroleum and . . .

 

2 August 2012 : Oil prices rise on surprise supply drop  {Associated Press}


The price of oil climbed to near $89 per barrel Wednesday after the government said supplies have dropped more than analysts expected. . . .

 

2 August 2012 : Oil prices climb on drop in US stockpiles  {theaustralian.com.au}


Oil prices have risen, boosted by a sharper than expected drop in US crude stockpiles that sparked hopes for stronger demand in the world's biggest . . .

 

2. Rig News

 

2 August 2012 : Transocean beats analyst expectations with rig cost control  {Businessweek.com}


Transocean Ltd. the world's largest offshore-rig contractor, reported second-quarter profit that beat analysts' estimates as it controlled . . .

3. News on Oil Exploration

 

2 August 2012 : Tanzania plans sovereign wealth fund for gas finds  {Reuters}


Tanzania is to set up a sovereign wealth fund to ring fence future earnings from its major gas discoveries in the southern parts of the . . .

 

2 August 2012 : Tanzania seeks resolution on Lake Malawi exploration dispute  {timeslive.co.za}


Tanzania Wednesday called for an amicable resolution to a dispute with Malawi over oil and gas exploration in Lake Malawi . . .

 

2 August 2012 : Centre plans to explore shale gas in Jharkhand  {Times of India}


The Centre has assigned the Central Mine Planning and Design Institute (CMPDI), a central public sector undertaking, with the job of exploring . . .

 

2 August 2012 : Shale oil exploration arrives in Alaska  {ktva.com}


This summer, companies are beginning to explore tapping Alaska's vast shale oil formations . . .

 

2 August 2012 : Shimshon officially declared gas discovery  {globes.co.il}


Isramco Ltd. and ATP Oil & Gas Corporation have officially declared the Shimshon well a natural gas discovery . . .

 

2 August 2012 : Cobalt sees positives in Angola Cameia appraisal  {ogj.com}


Cobalt International Energy Inc., Houston, said preliminary wireline log results indicate that the Cameia-2 appraisal well on Block 21/09 offshore . . .

 

2 August 2012 : Oil reserves found in Jaisalmer  {Times of India}


Public sector company Oil India Ltd (OIL) has for the first time found oil reserves at Poonam Singh ki Dhani in Nachna area of Jaisalmer 1,230 . . .

4. News on Oil Demand and Oil Consumption

 

2 August 2012 : Gasoline demand is weak, but US refiners shine  {Businessweek.com}


U.S. refiners are getting high prices for their gasoline and diesel while paying less for the crude and natural gas needed to make it . . .

5. News on Oil Output

 

2 August 2012 : Apache flows oil from second Bacchus well  {upstreamonline.com}


US independent Apache has started to flow oil from the second development well on the Bacchus field in the UK Central North Sea . . .

 

2 August 2012 : China's natural gas fields outpace crude production growth in H1  {platts.com}


China's major oil fields saw little output growth in the first half of 2012, while gas production at projects in central and western China . . .

 

2 August 2012 : Chevron to drill new wells in 350 locations  {thejakartapost.com}


PT Chevron Pacific Indonesia (CPI) would start drilling in 250 to 350 locations during the second half of this year to further increase . . .

 

2 August 2012 : Devon CEO says 2012 oil, gas output trending...  {foxbusiness.com}


Devon Energy Corp. (DVN) is likely to meet the lower end of its production guidance range for 2012 due to disruptions in natural-gas and . . .

 

2 August 2012 : Russia's oil output up to 10.34 million bpd in July  {Oilvoice}


Russian oil output was at 10.34 million barrels per day (bpd) in July, up from 10.32 million bpd in June . . .



























 

6. News on Oil Transportation

 

2 August 2012 : Iraq's Kurdish region to resume oil exports  {Reuters}


Iraq's semi-autonomous region of Kurdistan will restart oil exports this week in a bid to end a payment dispute with the central government . . .

 

2 August 2012 : S. Africa cuts Iran oil import ahead Clinton visit  {abcnews.go.com}


South Africa cut all crude oil imports from Iran in June amid heavy European and U.S. sanctions over Iran's nuclear program, a monthly government . . .

 

2 August 2012 : Kinder Morgan works with B.C. on pipeline expansion  {cloverdalereporter.com}


As the Enbridge pipeline debate and provincial tug-of-war continues, Houston-based company Kinder Morgan has said it will work with the . . .

 

2 August 2012 : Peru will tender new gas line by year's end  {Reuters}


Peru plans to auction off by the end of this year concessions to build two gas pipelines, Mines and Energy Minister Jorge Merino said on Wednesday . . .



 

7. News on Oil companies

 

2 August 2012 : Italian oil producer ENI reports worse than expected Q2 results  {chinapost.com.tw}


Italian oil major ENI on Wednesday reported worse than expected results for the second quarter but said it was confident . . .

 

2 August 2012 : Venezuela's PDVSA faces growing debt burden  {Reuters}


Venezuela's state oil company, PDVSA, will have to set aside between $4 billion and $7 billion annually for the next five years to make payments . . .

 

2 August 2012 : PTT Exploration & Production to delist Cove after its takeover  {foxbusiness.com}


Thailand's PTT Exploration and Production PCL is on track to complete its acquisition of Cove Energy PLC after 91.4% of Cove's shareholders accepted . . .

 

2 August 2012 : Marathon oil profit falls 61% amid low crude-oil prices  {foxbusiness.com}


Marathon Oil Corp.'s (MRO) second-quarter earnings fell 61% as lower prices for crude oil and natural-gas liquids hurt its exploration-and . . .






























 

8. Oil Contracts

 

2 August 2012 : Liquefied Natural Gas Limited reaches deal with PetroChina...  {proactiveinvestors.com.au}


Liquefied Natural Gas Limited has executed a non-binding Letter of Intent with PetroChina Australia regarding gas supply for . . .

 

2 August 2012 : Iraq says to cancel Total's Halfaya oil contract  {Reuters}


Baghdad is working to cancel Total's share in southern Iraq's Halfaya oilfield after the French company announced it signed agreements to develop oil in . . .

 

2 August 2012 : ADNOC in deal with Saudi firm  {gulfnews.com}


Abu Dhabi: Adnoc Distribution, the retail arm of Abu Dhabi National Oil Company (Adnoc), on Wednesday signed an agreement with . . .

 

2 August 2012 : Devon, Sumitomo in $1.4 billion deal, profit down  {ivcpost.com}


This latest oil and gas deal signals continued strong demand for shale drilling know-how from foreign partners. In April, Devon . . .

 

2 August 2012 : Iraqi Kurds win more oil deals, to restart exports  {Reuters}


Iraq's Kurdistan pledged on Wednesday to restart oil exports in a bid to ease tensions with the central government, as firms from France and Russia . . .

 

 

10. News on Oil Pollution

 

2 August 2012 : UN hails planned clean-up of oil spills in Nigeria's...  {rttnews.com}


The United Nations Environment Program (UNEP) on Wednesday welcomed the Nigerian government's recent decision to clean . . .

 

2 August 2012 : Enbridge safety practices to get closer look...  {Financial Post}


Canada's National Energy Board plans to subject Enbridge Inc to a series of safety audits in the coming months to make sure its pipeline control-room . . .

 

2 August 2012 : Chevron, Transocean must stop drilling after spill in Brazil  {USA today}


A federal court has given Chevron and driller Transocean 30 days to suspend all petroleum drilling and transportation operations . . .

 

1 August 2012 : Firm faces oil spill, conspiracy charges  {stuff.co.nz}


The listed Auckland firm faces conspiracy and oil pollution charges before Judge Beryl Howell in the US District Court in Washington DC today . . .

 

31 July 2012 : Indian ocean countries on track to prevent pollution  {dailynews.co.tz}


It is clear that this region is at risk of experiencing major pollution incidents from various sources including oil spills from ships and oil and gas . . .

 

31 July 2012 : BP back in growth mode, eyes oil sands  {Financial Post}


BP PLC's Gulf of Mexico spill two years ago washed up in Canada in a big way — the British oil major was forced to shed Canadian assets . . .

 

31 July 2012 : Enbridge spill provides fodder for Keystone critics  {torontosun.com}


Environmental groups demanded the U.S. State Department conduct a new, thorough analysis of the risks of transporting oil sands crude . . .

 

30 July 2012 : NZ's Sanford facing criminal trial in US  {tvnz.co.nz}


One of New Zealand's biggest fishing companies, Auckland's Sanford Ltd, faces a criminal jury trial tomorrow in Washington DC, charged . . .

 

30 July 2012 : Company plans repairs after Wisconsin oil spill  {New York Times}


Enbridge of Canada expects on Monday to begin replacing part of a pipeline that leaked more than 1,000 barrels of oil in a Wisconsin field . . .

 

29 July 2012 : U.S. pipeline agency probes Enbridge oil spill  {thestar.com}


The U.S. pipeline safety agency launched an investigation on Saturday into an oil spill in Wisconsin on Enbridge . . .



More Oil Pollution news  | ^Jump to the top^  



 

11. OPEC News

 

2 August 2012 : OPEC faces period of no growth  {Oilvoice}


In its five year forecast of the global crude oil markets, ESAI Energy points out that there will be little room for additional OPEC barrels . . .

 

12. General Oil News

 

2 August 2012 : China to react if India seeks oil in South China Sea  {Economic Times}


India and Vietnam should be given a strong response if they insist on exploring oil and gas in waters claimed by China, a Chinese newspaper has said . . .

 

13. News on Biofuels

 

2 August 2012 : Methes to hold grand opening for Sombra biodiesel plant Aug. 10  {biodieselmagazine.com}


Methes Energies Canada Inc. is holding a grand opening ceremony for its new 50 MMly (13 MMgy) multifeedstock biodiesel facility in . . .

 

2 August 2012 : US Senate tax bill would extend biodiesel, cellulosic tax credits  {platts.com}


The $1.01/gal federal tax credit for cellulosic fuel production, as well as the $1/gal biodiesel tax credit, would each be extended under a . . .

 

2 August 2012 : U.S. ethanol output rebounds from lowest in 2 years  {Reuters}


U.S. ethanol production last week rose for the first time in seven weeks, rebounding from the lowest level since at least June 2010 . . .

 

2 August 2012 : Lithuania wastes 1 mn tonnes of oil equivalent biofuel annualy  {baltic-course.com}

 

Thanks for visiting the site and your interest in oil and gas drilling

free counters