Api Bull 92L-2015 (American Petroleum Institute).Pdf

Covers fm Drilling Ahead Safely with Lost Circulation in the Gulf of Mexico API BULLETIN 92L FIRST EDITION, AUGUST 2015 Special Notes API publications necessarily address problems of a general nature[.]

Drilling Ahead Safely with Lost Circulation in the Gulf of Mexico

API BULLETIN 92L

FIRST EDITION, AUGUST 2015

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Page

1 Scope 1

2 Terms and Definitions 1

3 Background 5

3.1 General 5

3.2 Lost Circulation 5

3.3 Mud Weight 6

3.4 Drilling Margin 6

3.5 Calculating Equivalent Circulating Density (ECD) 7

4 Decision Tree Flow Charts 7

5 Solutions 13

Bibliography 14

Figures 1 Drilling Exploration Wells with Lost Circulation 9

2 Drilling Ahead below Salt with Lost Circulation 10

3 Drilling Depleted Zones with Lost Circulation 11

4 Managed Pressure Drilling with Lost Circulation 12

v

Lost circulation during drilling operations, in the form of both seepage and fracture losses, is a common occurrence inthe Gulf of Mexico (GoM) and other Outer Continental Shelf (OCS) environments Through extensive practicalexperience, operators and drilling contractors have learned that with proper information, planning and execution, lostcirculation can be safely managed to allow well construction goals to be met The methods used to repair or managelost circulation are based on well location, geology, pore and fracture pressures, drilling depth, well design, hydraulics,mud properties, and available contingencies

vi

2 Terms and Definitions

For the purposes of this document, the following definitions apply

This document requests changes to a well permit

NOTE This regulatory submittal document can require a risk assessment and/or procedures for the changes to be approved

2.4

ballooning (wellbore breathing)

The event in which fluid is lost to the formation while circulating and flows back into the wellbore when circulation is stopped

NOTE 1 During ballooning, mud returns will be at a steady or decreasing rate over time

NOTE 2 Increasing return rates are not expected with ballooning and would be an indication of the influx of formation fluids

NOTE 3 Return volumes are expected to be limited to the volume lost to the formation

2 API B ULLETIN 92L

2.6

development well

A well that is drilled to provide additional access to known hydrocarbon resources

NOTE In a development drilling scenario, geological information (e.g stratigraphic and geo-pressure) is often available from nearby wells

NOTE 3 The downhole static pressure can be measured with PWD prior to drilling the shoe (when the mud is without

a cuttings load) to establish a baseline value for mud static density

The effective density of the drilling fluid in the annulus while circulating, including the frictional pressure drop

in the annulus and the effect of cuttings load above any point of interest

geo-D RILLING A HEAD S AFELY WITH L OST C IRCULATION IN THE G ULF OF M EXICO 3

formation integrity test (FIT)

A test conducted to a pre-determined pressure to confirm the minimum pressure capacity of the open-hole formation and the cemented annular barrier at the casing shoe, commonly expressed in equivalent mud weight (ppg)

NOTE This test is done after drilling 10 ft to 50 ft (3 m to 15 m) of new formation below a cemented casing A FIT is considered an open-hole FIT if conducted after drilling more than 50 ft (15 m) of new formation

NOTE 1 LOTs can be affected by formation permeability, hole deviation, and temperature

NOTE 2 A LOT is considered an open-hole LOT if conducted after drilling 50 ft (15 m) of new formation

2.17

lost circulation

When drilling fluid flows into geological formations instead of returning up the annulus

NOTE Lost circulation includes seepage, partial, severe, or complete loss of returns during well operations

2.18

lost returns

The loss of whole drilling fluid into the formation

2.19

low integrity zone (i.e rubble zone) below salt

Interval below salt that can be mechanically unstable, outside of the normal geological sequence, and potentially a loss zone

minimum required mud volume

The minimum required usable volume that permits three circulations (two for surface stack rigs) of the wellbore excluding the marine riser at the expected/actual lost circulation rate when drilling ahead while experiencing partial or severe loss of returns

Equivalent to the density of formation water

NOTE Typically 8.65 ppg to 9.0 ppg for a GoM environment

2.23

partial returns

A portion of the drilling fluid is lost downhole when circulating the well

NOTE 1 The returns are less than the volume pumped

NOTE 2 Partial returns can also be expressed as a percentage of mud pumped

NOTE 1 Such losses can continue when the pumps are off

NOTE 2 Seepage losses typically are 20 bbl/hr or less Seepage losses can approach 30 bbl/hr when drilling an extended interval of highly permeable formations in larger diameter wellbores at high rates of penetration

2.27

standing full

The fluid level under static mud column conditions either 1) remains at the surface, or 2) the fluid level drop due to seepage losses is monitored and verified to ensure adequate hydrostatic pressure is maintained for well control

2.28

total lost returns

No mud returns from the hole while circulating

2.29

wellbore instability

When the stress around the wellbore exceeds the strength of the rock and cavings break-off of the wellbore wall as evidenced by hole enlargement, formation sloughing, fill or hole collapse

NOTE 1 In plastic type formations, such as salt, wellbore instability can actually reduce the hole diameter

NOTE 2 Wellbore instability can be mechanically (e.g stresses) or chemically induced

D RILLING A HEAD S AFELY WITH L OST C IRCULATION IN THE G ULF OF M EXICO 5

3 Background

3.1 General

Industry has developed, documented, and used practices to manage drilling with mud losses that include:

— the selection of lost circulation materials;

— the identification of pro-active operating practices to prevent losses; and

— the design of drilling fluids to manage equivalent circulating density (ECD)

Methodologies have also been developed for the prediction and onsite interpretation of fracture gradients in normal pressure, abnormal pressure, and pressure-depleted zones Using these proven practices, drilling with partial returns or with wellbore ballooning has been demonstrated to be a safe and accepted technique

in OCS well construction

3.2 Lost Circulation

Lost circulation has been safely managed during routine well construction operations for many years in both deepwater and shelf GoM wells Lost circulation can be caused by induced fracture propagation or experienced when drilling formations with specific geologic characteristics (e.g non-sealing pre-existing fractures, weak bedding planes, vugular zones) Non-sealing pre-existing fractures, cavernous or vugular zones (formations such as limestone or dolomites in which voids have been dissolved by ground water per API 65-2, C.3.2, 2nd edition) can be found in OCS waters off California and Florida

The loss rates of drilling fluid to the formation used in this document are as defined in API 65-2, C.3.4, 2nd edition Losses of drilling fluid to the formation have been arbitrarily defined in the following categories:

— seepage losses from 1 to 20 bbl/hr;

— partial losses from 20 bbl/hr to 50 bbl/hr;

— severe losses greater than 50 bbl/hr but the hole will remain full with the pumps off;

— complete losses, no returns while pumping or the hole will not remain full with the pumps off

Lost returns can be defined as a loss of drilling fluid pumped into the well greater than 20 bbls/hr when circulating Specific lost circulation mud treatments are not addressed in this document, nor are procedures for losses when drilling conductor or surface holes without a blowout preventer (BOP) stack

The techniques used have matured and there are various approaches to address lost circulation challenges When lost circulation occurs, drilling ahead is routinely and safely accomplished if properly risk assessed and planned

There are several options available to operators in the GoM when lost circulation occurs:

a) cure it prior to drilling ahead;

b) monitor and manage (treat mud and/or procedural change) the losses to allow drilling to progress with manageable returns or ballooning;

c) set casing/liner prior to drilling ahead;

d) use alternative drilling methods (pressurized mud cap drilling, managed pressure drilling, etc.);

e) cease drilling (when casing/liner cannot be set)

In the GoM, many of the geologically young formations require mud weights that approach the formation fracture pressure Formation stresses from overburden, stress orientation, tectonic events and hole angle all affect borehole stability Well path designs that include directional drilling, high angle drilling, and proximity to salt formations (creeping salt or low integrity zones below salt) may require higher mud weights in order to prevent borehole instability This increase in mud weight can cause lost circulation issues without causing well control issues

3.4 Drilling Margin

Drilling margin only applies to operations conducted while drilling The drilling margin is the difference between the mud weight in use and the lowest exposed formation fracture gradient The fracture gradient is first measured at the casing shoe when it is drilled out using either a formation integrity test (FIT), which is taken to a pre-determined pressure, or a leak-off test (LOT), whereby whole mud is pumped into the formation to establish the formation strength Operators should use local knowledge to determine which test (FIT or LOT) best supports the well construction objectives The lowest exposed fracture gradient may also

be measured after the shoe test in open hole with an ECD FIT test

Some of the factors affecting the selection of a drilling margin include depth, open-hole interval exposure, temperature, fracture gradient and mud properties (mud weight without cuttings) The formation strength component of a GOM drilling margin can be negatively affected by a LOT that is conducted using a synthetic

or an oil base mud

A prescriptive fixed safe drilling margin can result in unintended consequences as follows

a) A 0.5 ppg safe drilling margin at 7700 ft (2,347 m) TVD results in a 200 psi pressure differential, while at 30,000 ft (9144 m) TVD this safe drilling margin increases to a 780 psi (1379 kPa) difference At shallower depths than 7700 ft (2347 m) a 0.5 ppg safe drilling margin is difficult to implement due to the narrow margin between fracture gradient and pore pressure

b) A drilling margin of 2 % of the lowest exposed fracture gradient could be used to accommodate the changing fracture and pore pressure conditions within a drilling well Unfortunately, even this approach falls short of completely addressing the challenges provided by GOM wells, where well depths can vary from less than 5000 ft (1524 m) to greater than 35,000 ft (10,670 m) and where formation strengths vary significantly with lithology (e.g salt, limestone, sand, shale) and water depth

Therefore, prescriptive drilling margins are not recommended, rather a risk assessment should be performed

to establish safe drilling margins for each well and for each drilling interval within the well Drilling with losses should be conducted as described in Figure 1 through Figure 4

Using a relevant (non-arbitrary) drilling margin should result in well control and kick recognition being maintained when drilling ahead with losses The drilling margin should be risk-assessed and calculated based on sound engineering practices The drilling margin should be reassessed if lost circulation conditions change

Surface measurements and downhole measurements should be used consistently (don’t mix surface MW shoe tests with downhole mud weight [DHMW] or downhole shoe tests with surface MW)

Figure 1 through Figure 4 may not be applicable to lost returns/lost circulation scenarios associated with drilling into non-sealing pre-existing fractures or vugular zones, as the fracture gradient can approach pore