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 Special Notes API publications necessarily address problems of a general nature With respect to particular circumstances, local, state, and federal laws and regulations should be reviewed Neither API nor any of API's employees, subcontractors, consultants, committees, or other assignees make any warranty or representation, either express or implied, with respect to the accuracy, completeness, or usefulness of the information contained herein, or assume any liability or responsibility for any use, or the results of such use, of any information or process disclosed in this publication Neither API nor any of API's employees, subcontractors, consultants, or other assignees represent that use of this publication would not infringe upon privately owned rights API publications may be used by anyone desiring to so Every effort has been made by the Institute to assure the accuracy and reliability of the data contained in them; however, the Institute makes no representation, warranty, or guarantee in connection with this publication and hereby expressly disclaims any liability or responsibility for loss or damage resulting from its use or for the violation of any authorities having jurisdiction with which this publication may conflict API publications are published to facilitate the broad availability of proven, sound engineering and operating practices These publications are not intended to obviate the need for applying sound engineering judgment regarding when and where these publications should be utilized The formulation and publication of API publications is not intended in any way to inhibit anyone from using any other practices Any manufacturer marking equipment or materials in conformance with the marking requirements of an API standard is solely responsible for complying with all the applicable requirements of that standard API does not represent, warrant, or guarantee that such products in fact conform to the applicable API standard Users of this Bulletin should not rely exclusively on the information contained in this document Sound business, scientific, engineering, and safety judgment should be used in employing the information contained herein All rights reserved No part of this work may be reproduced, translated, stored in a retrieval system, or transmitted by any means, electronic, mechanical, photocopying, recording, or otherwise, without prior written permission from the publisher Contact the Publisher, API Publishing Services, 1220 L Street, NW, Washington, DC 20005 Copyright © 2015 American Petroleum Institute Foreword Nothing contained in any API publication is to be construed as granting any right, by implication or otherwise, for the manufacture, sale, or use of any method, apparatus, or product covered by letters patent Neither should anything contained in the publication be construed as insuring anyone against liability for infringement of letters patent Shall: As used in a standard, “shall” denotes a minimum requirement in order to conform to the specification Should: As used in a standard, “should” denotes a recommendation or that which is advised but not required in order to conform to the specification This document was produced under API standardization procedures that ensure appropriate notification and participation in the developmental process and is designated as an API standard Questions concerning the interpretation of the content of this publication or comments and questions concerning the procedures under which this publication was developed should be directed in writing to the Director of Standards, American Petroleum Institute, 1220 L Street, NW, Washington, DC 20005 Requests for permission to reproduce or translate all or any part of the material published herein should also be addressed to the director Generally, API standards are reviewed and revised, reaffirmed, or withdrawn at least every five years A one-time extension of up to two years may be added to this review cycle Status of the publication can be ascertained from the API Standards Department, telephone (202) 682-8000 A catalog of API publications and materials is published annually by API, 1220 L Street, NW, Washington, DC 20005 Suggested revisions are invited and should be submitted to the Standards Department, API, 1220 L Street, NW, Washington, DC 20005, standards@api.org iii Contents Page Scope Terms and Definitions 3.1 3.2 3.3 3.4 3.5 Background General Lost Circulation Mud Weight Drilling Margin Calculating Equivalent Circulating Density (ECD) Decision Tree Flow Charts Solutions 13 5 6 Bibliography 14 Figures Drilling Exploration Wells with Lost Circulation Drilling Ahead below Salt with Lost Circulation 10 Drilling Depleted Zones with Lost Circulation 11 Managed Pressure Drilling with Lost Circulation 12 v Introduction Lost circulation during drilling operations, in the form of both seepage and fracture losses, is a common occurrence in the Gulf of Mexico (GoM) and other Outer Continental Shelf (OCS) environments Through extensive practical experience, operators and drilling contractors have learned that with proper information, planning and execution, lost circulation can be safely managed to allow well construction goals to be met The methods used to repair or manage lost circulation are based on well location, geology, pore and fracture pressures, drilling depth, well design, hydraulics, mud properties, and available contingencies vi Drilling Ahead Safely with Lost Circulation in the Gulf of Mexico Scope This bulletin identifies items that should be considered to safely address lost circulation challenges when the equivalent circulating density (ECD) exceeds the fracture gradient It addresses drilling margins and drilling ahead with mud losses, which are not addressed in API 65-2 It provides guidance when lost circulation is experienced with either surface or subsea stack operations (excluding diverter operations) These practices may apply to other Outer Continental Shelf (OCS) environments such as offshore California and Florida Terms and Definitions For the purposes of this document, the following definitions apply 2.1 abnormal pressure Pressures greater than normal pressure, i.e formation pressure that exceeds the gradient of a continuous column of water terminating at the surface or the seafloor NOTE Normal pressure in the GoM region is commonly considered to have gradients in the range of 8.65 ppg to 9.0 ppg Abnormal pressure has a higher gradient 2.2 annulus friction pressure Pa The steady state circulating pressure loss of a cuttings free fluid occurring within the drill string and casing and/or open-hole annulus NOTE The term does not include pressure effects associated with cuttings loading 2.3 application for permit to modify/revised permit to drill APM/RPD 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 During ballooning, mud returns will be at a steady or decreasing rate over time NOTE fluids Increasing return rates are not expected with ballooning and would be an indication of the influx of formation NOTE Return volumes are expected to be limited to the volume lost to the formation 2.5 depleted zone A geologic interval having a pore pressure lower than the original reservoir pressure caused by production from that interval NOTE The reduction in pore pressure can create a lower fracture pressure within the interval API BULLETIN 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 2.7 downhole mud weight DHMW The static mud weight (expressed in ppg) that exists in the well, accounting for mud compressibility and thermal effects that can increase or decrease the value from the surface mud weight NOTE This term does not include the contribution to the effective fluid density caused by drill cuttings load When the DHMW has the cuttings load included, it becomes the ESD NOTE Downhole mud weight can be estimated with mud hydraulics programs and can be measured with pressure while drilling (PWD) when drill cuttings are not present NOTE 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 2.8 drilling Activities that increase the measured depth of the well (this does not include reaming, tripping, circulating, running casing, blowout preventer testing, cementing, hole enlargement, etc.) 2.9 drilling margin The difference between the lowest estimated fracture gradient (ppg) at a given depth in the open-hole interval (including at the casing shoe) and the drilling fluid density (ppg) NOTE In API 96 the drilling margin is defined as the difference between the maximum pore pressure and the minimum effective fracture pressure NOTE Cuttings load should not be included when using downhole mud weight for drilling margin calculations 2.10 equivalent circulating density ECD 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 2.11 equivalent static density ESD The effective mud weight consisting of the surface mud weight accounting for mud compressibility and thermal effects plus drill cuttings load NOTE ESD = DHMW + CL 2.12 exploration well A well without a direct offset, not having the geologic information and control (e.g stratigraphic or geopressure information) that would typically be available from a nearby well DRILLING AHEAD SAFELY WITH LOST CIRCULATION IN THE GULF OF MEXICO 2.13 fingerprinting The characterization of the volume and rate of fluid flow back to the pit system from the wellbore and the surface circulating system (as a function of time) after the pumps are shut down NOTE A characteristic flowback response (historical trend) is established for use in distinguishing normal flow back trends from a wellbore influx (i.e., kick) 2.14 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 2.15 fracture gradient The pressure required to create fracture growth in rock at a given depth, commonly expressed in equivalent mud weight 2.16 leak-off test LOT A test conducted to a pressure that initiates a fracture in an open-hole formation and thus determines the fracture gradient (i.e integrity) in the vicinity of the cemented casing shoe NOTE LOTs can be affected by formation permeability, hole deviation, and temperature NOTE 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 2.20 managed pressure drilling MPD Adaptive drilling process used to control the annular pressure profile using a combination of fluid density and surface pressure or fluid column height 2.21 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 4 API BULLETIN 92L NOTE This volume can include mud that is available from surface pits (both active and reserve) and the mud on boats at the rig site NOTE The volume is calculated by multiplying expected/actual lost circulation rate by circulation time 2.22 normal pressure 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 The returns are less than the volume pumped NOTE Partial returns can also be expressed as a percentage of mud pumped 2.24 pressure regressions Formation intervals that have lower pore pressure gradients (and correspondingly lower fracture gradients) than the pressure gradients of intervals immediately above them NOTE The reduced gradients are naturally occurring and not associated with prior production 2.25 risk assessment Identification, evaluation and estimation of levels of risk that are involved in a situation 2.26 seepage losses Loss of drilling fluid into the rock matrix (not into induced fractures) due to the permeability of the exposed formations NOTE Such losses can continue when the pumps are off NOTE 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 In plastic type formations, such as salt, wellbore instability can actually reduce the hole diameter NOTE Wellbore instability can be mechanically (e.g stresses) or chemically induced DRILLING AHEAD SAFELY WITH LOST CIRCULATION IN THE GULF OF MEXICO 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 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) 6 API BULLETIN 92L The current practice in the GoM is to have the operator set a safe drilling margin 3.3 Mud Weight It is common for the mud weight used in GoM wells to approach the fracture gradient of the formations being penetrated Achieving the well's geologic and commercial objectives is dependent on the ability to safely manage small drilling margins The equivalent mud weight has to be greater than the pore pressure, but also has to prevent wellbore instability 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 % 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 through Figure 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 through Figure 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 DRILLING AHEAD SAFELY WITH LOST CIRCULATION IN THE GULF OF MEXICO pressure and repair/treatment of the lost returns may not be possible If lost returns occur due to encountering non-sealing pre-existing fractures and/or vugular zones, then the fracture gradient may be no higher than the equivalent of the formation pore pressure, unless determined otherwise Therefore, it may not be possible to maintain a mud weight any higher than the pore pressure, and when these zones are pressure-depleted, the wellbore can experience complete lost returns regardless of the mud weight utilized, including when drilling with seawater Wells can and have been safely drilled in these types of formations with complete lost returns in OCS waters such as offshore California and Florida 3.5 Calculating Equivalent Circulating Density (ECD) The following formula applies when cuttings are included ECD = MW + CL + Pa/(0.052 × TVD) where CL is the cuttings load, in ppg; MW is the mud weight, in ppg; Pa is the annular friction pressure, in psi; TVD is the true vertical depth of the point of interest, in ft ECD is a function of downhole mud weight (ECD = ESD + annular friction) It can be directly measured using PWD tools NOTE Equivalent static density (ESD) includes cuttings load An ECD test is performed by circulating at a various reduced rates to determine a circulating rate that does not induce losses, confirming that drilling can safely continue at the reduced rate A predicted ECD is estimated using hydraulic modeling that can considers drilling and well parameters including rate of penetration, pump rate, well architecture, drilling fluid rheological properties and pressure/ temperature effects In Figure through Figure 4, the predicted ECD test can include mud weight increases, which the ECD test should account for This can require an increased circulation rate to adequately address the increase in ECD that is caused by additional mud weight Decision Tree Flow Charts The decision tree flow charts presented in Figure through Figure depict common scenarios of lost circulation specifically addressing issues for both OCS and Deepwater GoM wells These flow charts can be used as an aid to safely drill ahead when lost circulation occurs and the required criteria and procedures are met Four lost circulation decision tree flow chart scenarios have been developed: — Figure 1, Drilling Exploration Wells with Lost Circulation; — Figure 2, Drilling Ahead below Salt with Lost Circulation; — Figure 3, Drilling Depleted Zones with Lost Circulation; — Figure 4, Managed Pressure Drilling with Lost Circulation Although similar to one another, each chart is unique and specific to the circumstances surrounding the lost circulation event 8 API BULLETIN 92L Key understandings for use of the flow charts are the following a) If measuring the mud weight under downhole conditions the cuttings load should not be included (as described in the definitions of DHMW) b) The charts (and drilling margins) are to be applied to drilling operations only (these operations not include reaming, tripping, circulating, running casing, BOP testing, cementing, hole enlargement, and logging) c) The ECD test is performed by circulating at various reduced rates to determine a circulating rate that does not induce losses (with the BOP open), to confirm that drilling can continue at a reduced rate It can be performed before a critical operation such as weighting up the mud or after a lost circulation event It may be used in conjunction with the predicted ECD to model mud weight increases Surface and downhole measurements should be kept separate d) Fingerprinting establishes the expected decrease in the rate of fluid flow back versus time when the pumps are stopped Deviations from the historical flow back trend, established at connections, are useful in identifying possible influxes of formation fluids e) The hole standing full allows for seepage losses f) Before using the flow charts, surface losses (open valves, solids control) and downhole mechanical losses (e.g., riser, bell nipple, ring gaskets or wellhead leaks) have to be addressed g) The logging while drilling (LWD) tools used can be nearly 200 ft (61.0 m) in length, thus requiring up to 300 ft (91.4 m) of drilling to allow the drilled hole to be evaluated (to determine if the loss zone is on bottom or to drill through a depleted zone) The low integrity zone below salt is more variable in length, with 400 ft (121.9 m) shown in the charts to allow for better identification of the zone to determine if drilling has progressed into formations having normal competency Electric line logs can be substituted for LWD logs as determined by the operator h) Depleted zones are encountered primarily in development wells, which have more geological information available, thereby reducing risk DRILLING AHEAD SAFELY WITH LOST CIRCULATION IN THE GULF OF MEXICO Is lost circulation encountered? No Continue normal operations Yes Can ECD be reduced to avoid dynamic mud losses (e.g changing mud properties, modified flow geometry, lower circulating rate)? Yes No No Does the hole stand full with a static mud column? Yes No Well control operations If the hole is ballooning, has the operator confirmed that that the well is not flowing? Yes Do you have more than the minimum required mud volume on location? Repair lost circulation Yes Yes Yes Is mud weight sufficient to control expected pore pressure? No Is an increase in mud weight predicted for additional hole section to be drilled? No Is the expected pore pressure when drilling ahead less than the pressure exerted by a static mud column of the current MW? Yes No Is the loss zone (the low integrity zone) located on bottom (as determined by LWD or other methods)? Yes No Yes Continue normal operations Stop drilling, get more mud or repair lost circulation No Yes Is open-hole FIT (ECD test) above predicted ECD (to drill ahead, submit fingerprint plot)? No Stop drilling, run casing File APM/RPD with regulator demonstrating that the well can be safely drilled to the planned interval depth Notify regulator Submit fingerprint plot if ballooning is occurring Drill ahead no more than 300 ft (91 m) MD (monitoring LWD and/or samples) to cover loss zone and set casing or evaluate geology NOTE Before drilling an exploration well, a lost circulation plan should be in place that has been vetted by the Drilling Team Figure 1—Drilling Exploration Wells with Lost Circulation 10 API BULLETIN 92L Is lost circulation encountered? No Yes Can ECD be reduced to avoid dynamic mud losses (e.g changing mud properties, modified flow geometry, lower circulating rate)? Yes Continue normal operations No No Does the hole stand full with a static mud column? Yes Well control operations No If the hole is ballooning, has the operator confirmed that that the well is not flowing? Yes Do you have more than the minimum required mud volume on location? Repair lost circulation Yes Is mud weight sufficient to control expected pore pressure? Yes No Yes No No Is an increase in mud weight predicted for additional hole section to be drilled? No Is the expected pore pressure when drilling ahead less than the pressure exerted by a static mud column of the current MW? Yes Is more than 400 (122 m) MD required before drilling through low integrity zone as confirmed by LWD and/or Paleo information? No Yes Yes Continue normal operations Stop drilling, get more mud or repair lost circulation No Yes Is open-hole FIT (ECD test) above predicted ECD (to drill ahead, submit fingerprint plot)? No Stop drilling run casing File APM/RPD with regulator demonstrating that the well can be safely drilled to the planned casing point Notify regulator Submit fingerprint plot if ballooning is occurring Drill ahead no more than 400 ft (122 m) MD (Monitoring LWD and/or Paleo samples) and set casing NOTE Before exiting base of salt, treat mud system to lower ECD Follow subsalt drilling procedure and LCM plan (e.g pre-treatment, sweeps, pills) in place and be ready to pump as required Figure 2—Drilling Ahead below Salt with Lost Circulation DRILLING AHEAD SAFELY WITH LOST CIRCULATION IN THE GULF OF MEXICO 11 No Is lost circulation encountered? Yes Can ECD be reduced to avoid dynamic mud losses (e.g changing mud properties, modified flow geometry, lower circulating rate)? Yes Continue normal operations No No Does the hole stand full with a static mud column? Yes Well control operations No If the hole is ballooning, has the operator confirmed that that the well is not flowing? Yes Repair lost circulation Yes Is mud weight sufficient to control expected pore pressure? Do you have more than the minimum required mud volume on location? No Yes Yes No No No Is an increase in mud weight predicted for additional hole section to be drilled? Since hydrocarbons are present or expected in the interval, is the expected pore pressure less than the pressure exerted by a static mud column of the Yes Is more than 300 ft (91 m) MD required before setting casing? No Yes Yes Continue normal operations Stop drilling, get more mud or repair lost circulation No Yes Is open-hole FIT (ECD test) above predicted ECD (to drill ahead, submit fingerprint plot)? No Stop drilling run casing File APM/RPD with regulator demonstrating that the well can be safely drilled to the planned casing point Notify regulator Submit LCM plan and fingerprint plot (if ballooning) for connections Drill ahead no more than 300 ft (91 m) MD (to allow LWD log to be obtained) and set casing NOTE Use reservoir knowledge (i.e pressure, temperature, fracture size) to determine LCM plan (i.e particle size, bridging agents, concentration) Implement prior to drilling depleted zone Figure 3—Drilling Depleted Zones with Lost Circulation 12 API BULLETIN 92L Is lost circulation encountered? Yes Can ECD be reduced to avoid dynamic mud losses (e.g., changing mud properties, reducing surface pressure or downhole otherwise managing No Yes No Does the hole stand full with a static mud column, including applied surface pressure? No No No Yes Continue normal operations Yes Can MPD operations be continued with modified mud properties, lower circulating rate and/or modified flow geometry? Has the operator confirmed that that the well is not flowing? Well control operations Yes Do you have more than the minimum required mud volume on location? Repair lost circulation Yes Yes No Yes Effective mud weight sufficient to control expected pore pressure? No Is an increase in effective mud weight predicted for additional hole section to be drilled? Is the expected pore pressure less than the pressure exerted by an effective mud weight? Yes No Is more than 300 ft (91 m) MD required before setting casing? Yes File APM/RPD with regulator demonstrating that the well can be safely drilled to the planned casing point Yes Continue normal operations Stop drilling, get more mud or repair lost circulation No No Yes Is open-hole FIT (ECD test) above predicted ECD (to drill ahead, submit fingerprint plot)? No No Stop drilling, run casing Notify regulator Submit LCM plan and fingerprint plot (if ballooning) for connections Drill ahead no more than 300 ft (91 m) MD (To allow LWD log to be obtained) and set casing NOTE Use reservoir knowledge (i.e pressure, temperature, fracture size) to determine LCM plan (i.e particle size, bridging agents, concentration) Implement prior to drilling depleted zone Figure 4—Managed Pressure Drilling with Lost Circulation DRILLING AHEAD SAFELY WITH LOST CIRCULATION IN THE GULF OF MEXICO 13 Solutions Drilling ahead safely with partial returns (or wellbore ballooning) before setting casing/liner has been routinely accomplished in the GoM by using industry best practices such as: a) fingerprinting of connections; b) logging while drilling (LWD) data analysis; c) use of pore pressure detection/prediction tools; d) performing appropriate risk assessment; e) using lost circulation procedures: 1) raise near-bore fracture gradient with squeeze treatments (LCM or cement), 2) lower ECD thru modified mud properties, 3) lowering ECD (cuttings reduction) through reducing ROP or increased circulation, 4) lowering ECD by reducing flow rate, 5) use of managed pressure drilling (MPD) technology to counteract high ECDs, 6) use of pressure while drilling (PWD) tools to measure ECD; f) establishing criteria for determining a minimum amount of mud volume onsite; g) having a contingency plan and materials available onsite to address potential lost circulation Bibliography [1] API Standard 65-2, 2nd Edition, Isolating Potential Flow Zones During Well Construction [2] API Recommended Practice 96, Deepwater Well Design and Construction 14