SPE-178786-MS

IADC/SPE-178786-MS
First Successful Implementation of an Advanced Fibrous Organic Based
LCM and Optimized Casing Design in Europe: A Case History From Drilling
a 6022 m HPHT Exploration Well in Vienna Basin, Austria
Khaled Abdelaal, Kjell Ovrevik, and Rudolf-Nikolaus Knezevic, OMV Austria; Ryanto Husodo, Drilchem
Copyright 2016, IADC/SPE Drilling Conference and Exhibition
This paper was prepared for presentation at the IADC/SPE Drilling Conference and Exhibition held in Fort Worth, Texas, USA, 1–3 March 2016.
This paper was selected for presentation by an IADC/SPE program committee following review of information contained in an abstract submitted by the author(s).
Contents of the paper have not been reviewed by the International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to
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Abstract
The paper presents findings of a case history based on the first application of specialized organic fibre lost
circulation materials (LCM) in Europe. It lists technical challenges encountered during the recent drilling
of HPHT exploration well Stripfing T1 to 6022 mMD and describes how new fibrous organic LCM have
proven their value in a range of lost-circulation applications in the Vienna basin. The paper will also
elaborate on the narrow mud window available and the main drivers for well design along with
contingency concepts.
The operator identified an innovative LCM which had the characteristics that it is plastic, deformable
and can be squeezed into a loss zone resulting in an effective seal being formed across the loss zone with
an internal filtercake rather than a high loss filtercake forming on the exterior of the wellbore. Several pills
containing this product were used achieving excellent results when applied according to a specific
procedure. The paper will look in detail at this procedure and highlight the input from detailed
decision-tree charts, and the characteristics and wettability of fibres.
The Vienna Basin has a history of mud losses ranging from continuous seepage to severe losses. The
main concerns while planning the Stripfing T1 well were the magnitude of overpressure in combination
with the expected losses. The above had been the root cause of previous failures.
Several attempts to cure the losses with standard LCM had proven unsuccessful, as a consequence the
operator decided to adopt a new approach using a specialized LCM product in order to avoid running
casing earlier. Successful implementation of this advanced technique allowed the operator to drill the well
using only 3 casing strings and a final hole size of 8 ½ in. without reducing the mud weight.
The level of success achieved by using these materials suggests it should be considered as the preferred
standard practice for curing any type and volume of losses.
Introduction
As thrust sheets of the Eastern Alps were propagating to the North-West, a basin with ~ 200 km x 55 km
was formed as a wedge top zone (DeCelles and Giles, 1996). Later - during Middle to Upper Miocene -
(~16 – 7 Ma) a SSW –NNE oriented pull apart basin was formed.

While the stratigraphy of the Neogene basin fill is considered well known, the underlying Alpine
structures are much harder to characterize from seismic data.
Two nappes, part of the Northern Calcareous Alps, namely the Göller Nappe (SE) and Frankenfels-
Lunzer Nappe have formed (predominantly) structural traps which have been targeted in Hydrocarbon
exploration since the late 1950s. The location of the well was selected to penetrate the last undrilled
structural high in the basin assumed to contain hydrocarbons.
When the operator was planning to drill the exploration vertical well Stripfing T1 to 4655 mMD in
2012, the operator wanted to avoid the problems that had plagued the drilling of past offset wells. Bottom
hole assembly (BHAs) had been lost due to complete losses, pack offs and stuck problems.
Hence, the operator decided to conduct a Geomechanical Earth Model (GEM) study in order to analyze
drilling events encountered in the offset wells and recommend safe mud weight window for the planned
well.
The Stripfing T1’s geological model had to be revised resulting in extension of the planned TD of the
well by 450 m. Consequently, diiferent well design options had to be engineered within a limited time
frame.
This paper describes how the operator designed and drilled one of its most challenging wells in Vienna
basin successfully deeper than planned with a medium-sized rig while maintaining acceptable safety
standards. Figure 2 shows the actual drilling time-depth of the well versus the offset wells. All the offset
wells had very considerable NPT. The paper also describes the importance of using these special organic
fibers (product A and B) for curing any type and volume of losses.
Figure 1—Geological map of Austria; Units in the NE of Austria (Quaternary cover removed), including location of Stripfing T1 well
(crosshair); after Wessely et al, 2006, p. 165, altered
2 IADC/SPE-178786-MS

Well Challenges and Innovative Practices
Uncertain formation thickness and PP/FG data below HPHT section
The availability of PP/FG data up to the pressure ramp zone was used as inputs for well design. For the
underlaying HPHT section, there was no data available from any of the surrounding wells. The deepest
well drilled in the field (Well C – TD: 4482 mMD) experienced a series of Љloss & kickЉ situations. This
had been the root cause of failure on previous attempts (Figure 3) due to the thickness of the formation
being difficult to estimate. The key challenge in the overpressure zone was to understand the losses
mechanism and how to cure it.
Figure 2—Actual drilling time-depth of Stripfing T1 well versus the offset wells
IADC/SPE-178786-MS 3

To reduce the uncertainty of pore pressure, a GEM study was conducted by a third party where a
wellbore stability model was created for the planned well. Referring to experiences from drilling a recent
well in a similar geological setting, a revision of the geological model was carried out late in the planning
cycle. The planned final well TD was changed to 5105 mMD prior the well spud by 3 months.
To overcome this issue, a flexible well design (Figure 4) was adopted with possible contingent liners
to isolate the high pressure zone from anticipated zone of normal pressure below if required. The most
critical part in the well was setting 13 3/8 in. casing at the right depth to have sufficient fracture gradient
to handle a kick tolerance volume of 50 bbl. It had to be set as deep as possible without accidentally
penetrating the over pressure zone.
Figure 4—Well design options (plan versus actual – not to scale)
Figure 3—Stick chart for offset wells

The main driver for option 1 and 2 were the actual developments of PP/FG in combination with the
leak-off test (LOT) obtained at the 13 3/8 in. casing shoe. If the LOT was less than 1.85 SG an additional
liner would have to be run (option 1). If LOT was greater than 1.85 SG, the 12 ¼ in. hole could be
extended to 4250 mMD (option 2). The main driver when considering option 3 was running 13 3/8 in.
casing shallower at 2750 mMD assuming seepage losses within Trais-Anis formation could not be cured
with standard LCM. The 11 3/4 in. liner was planned to be run at 3580 mMD if the LOT at 13 3/8 in.
casing shoe was less than 1.88 SG. This option considered a possible well deepening in case of larger
formation thicknesses than predicted.
Option 3 covered all anticipated risks associated with well design, though it was not the preferred
option. The reason for this were the extra cost of 2 additional strings and the associated risk of hole
enlargement to 14 ¾ in. hole in order to accommodate the 11 ¾ in. liner. The hole enlargement operation
would be carried out within Gosau formation, associated with wellbore instability problems.
Wellbore instability
Gosau formation expected below basin floor was known for breakouts from offset wells. The end of well
reports from offset wells reported hole instability and blocks of rock falling into the wellbore, suggesting
that the matrix had been washed away during the drilling phase (Figure 5).
For the planned well, a newly formulated mud system was introduced. The objective was to increase
the stability of the rock matrix by enhancing inhibition and using plugging materials such as asphaltic
compound and Product A. These two products would plug the openings in the shale and thereby slow
down the water penetration into the matrix. A critical fluid screening indicated that the new mud system
should be a KCl/polymer system composed of the following (2% to 3% polyamine, 8.6 kg/m3
asphaltic
compound plus 8.6 kg/m3
product A).
Wellbore breakout could be induced by using aggressive drilling & tripping parameters. Since the
Gosau formation is very sensitive to any severe changes in the used parameters, it was a must to use
constant drilling parameters and to avoid excessive backreaming which could lead to destabilizing the
formation. Staging pumps on/off during connections in combination with hole cleaning reduced pressure
shocks.
From recent drilling experiences from wells penetrating the Gosau formation, a lot of cavings over
shaker and tights spots had been observed and reported. Hard reaming was applied during tripping out
Figure 5—Conglomerates of Turonian age, part of ؆Gosau؆ group, in an outcrop near the rim of Vienna basin

with 8 ½ in. BHA. As a consequence the 7 in. liner was equipped with a reamer shoe where hard reaming
(up to 50 tons) had to be applied in order to get the liner to bottom (Figure 6).
For Stripfing T1 well, surge and swab ECD was a challenge but manageable during tripping operation.
Careful attention was made to avoid inducing any kick since only 5 bar overbalance (static) was applied
and also to avoid destabilizing the Gosau formation. To avoid any surge and swab problems, a
recommended tripping procedure was engineered based on Hydraulic simulations using actual mud
rheology and BHA/wellbore geometry. To ensure a smoother trip; it was recommended to pump out to
maintain a swab ECD value between static mud weight and drilling ECD by adjusting the tripping speed
and flow rate in a constant manner to avoid any wellbore breakouts.
It was a must to keep observing any sudden increase in ECD, SPP and/or Torque reading all the time
while pumping out and/or backreaming with BHA as an early waring sign for pack-off event. The main
target is avoiding backreaming unless hole dictates; the backreaming parameters were calculated using a
torque / drag software in order to knowthe safe boundary limits where excessive backreaming could lead
to wellbore instability problems.
Figure 7—Running 9 5/8 in. casing through Gosau formation for Stripfing T1 well
Figure 6—Tripping parameters for running 7 in. iner from a recent drilled well

Narrow operating mud window and limited kick tolerance volume
In the execution phase, partial losses (up to 6 m3
/hr) were encountered during drilling 17 ½ in. hole at
2610 mMD within Trias-Anis formation. Several attempts to cure the losses with standard LCM proved
unsuccessful leading the operator to select Љproduct AЉ based on lab results. After curing all losses drilling
continued to section TD. The 13 3/8 in. casing was run and cemented at 2954 mMD (~ 100m into top of
Gosau formation as per plan.
Planning was based on a maximum anticipated pore pressure of 1.65 SG in 12 ¼ in. hole. This was
despite the maximum recorded formation pressure being 1.56 SG from offset wells.
The recorded LOT at 13 3/8 in. casing shoe was 1.77 SG. Considering the planned worst case scenario
for pore pressure of 1.65 SG plus 0.12 SG kick intensity (as per the operator’s casing design policy for
exploration wells), it was not technically possible to drill ahead with this low LOT value. The project team
decided to consider the maximum recorded pore pressure of 1.56 SG from the offset well plus 0.12 SG
kick intensity for the kick tolerance calculations instead of using the 1.65 SG pore pressure. On the basis
of this assumption, it was agreed to continue drilling 12 ¼ in. hole to the maximum depth of 3590 mMD
with a kick tolerance volume of 50 bbl.
Drilling 12 ¼ in. hole was resumed with controlled rate of penetration (ROP) of 12 m/hr and stopped
by two kicks (3281 mMD and 3371 mMD) of less than 700 liter, 1.56 SG EMW. Drilling was resumed
with 1.57 SG to 3590 mMD.
The decision the team faced now was either to enlarge 12 ¼ in. hole to 14 ¾ in. in order to run 11 ¾
in. liner (option 1) to have sufficient fracture gradient to handle a kick tolerance of 50 bbls or to continue
drilling 12 ¼ in. hole with a reduced kick tolerance volume. The kick tolerance calculation was updated
to determine the available margin to continue drilling ahead to 4250 mMD (planned section TD). It was
agreed that a 25 bbl gas kick using 0.12 SG kick intensity above 1.56 SG pore pressure could be circulated
out safely without breaking down formation below the 13 3/8 in. casing shoe.
A detailed risk assessment was made, evaluated and discussed with the project team prior resuming
drilling ahead. It was very important that rig crew was fully briefed and alert. It was well known from the
offset wells that severe losses could be expected to occur below the pressure ramp zone. In order to
continue drilling ahead safely in the same hole size, the ROP was limited to 5 m/hr, finger-printing each
connection and low kick tolerance procedures were set in place.
● Flow check any drilling break more than 2 m – Rotate / reciprocate slowly while flow checking.
● Back flow monitoring (on connections and shut-off pumps) will be closely monitored.
● Maintain drilling parameter trend sheets to indicate downhole changes.
● Record and communicate control of mud volumes and transfers.
Drilling 12 ¼ in. hole was continued from 3590 mMD and forced to stop at 3840 mMD when severe
losses were encountered (18 m3
/hr). Several attempts to cure the losses with standard LCM for few days
proved unsuccessful leading the operator to select Љproduct BЉ based on lab results. The severe losses were
then cured successfully and drilling continued to 4501 mMD (section TD). Severe losses were encoun-
tered several times during drilling (up to 50 m3
/hr, see table 2). These severe losses occurred in heavily
fractured limestone and were cured by using product B. It was clearly visible from the real-time data, once
LCM (product B) is pumped downhole and reached to the bottom, the losses were stopped. One case
product B LCM had to be squeezed into formation by applying 10 bar.

Since the Hauptdolomite reservoir was not encountered at 4250 mMD, a dispensation for using a
reduced kick intensity of 0.06 SG instead of 0.12 SG was requested based on the fact that the maximum
pore pressure scenario of 1.56 SG was already penetrated at 3371 mMD. This allowed deepening the 12
¼ in. hole to a maximum depth of 4501 mMD providing a kick tolerance volume of 95 bbl (Figure 8).
Table 1—Product B, volume and concentrations
Hole Size Pill Volume m3
Comments
17 ½ in. 25 Avoid contamination / dilution of pill, cover ϩ/- 100 m open hole
12 ¼ in. 15
8 ½ in. 10
Loss type Loss rate m3
/hr Product B concentration
Partial Ͼ 6 - 15 70-100
Severe - Total Ͼ15 100-125
Table 2—Sumary of loss zones, and strata associated, paralleled with image interpretation in the vicinity
Loss Zone Root cause Formation micro-imager logs reference
1610m-1842m Triassic Anis/Ladin Fractured LST Poor data, conductive frac @ 1701m
3303m Conglomerate Cond fracs @ 3282m and 3312m
3832m Triassic Anis/Ladin Fractured LST Lots of fracs @ 3834m, conductive fracs @ 3837-3838m
3840m Triassic Anis/Ladin Fractured LST Lots of fracs @ 3834m, conductive fracs @ 3837-3838m
3896m Triassic Anis/Ladin Fractured LST Bad data
3909m Triassic Anis/Ladin Fractured LST Bad data
3970m Triassic Anis/Ladin Fractured LST conductive fracs @ 3972-3973m
4016m Triassic Anis/Ladin Fractured LST numerous fracs @ 4020m
4455m Triassic Anis/Ladin Fractured LST numerous fracs @ 4450m-4459m
4499m Triassic Anis/Ladin Fractured LST No data due to casing point
4771m Triassic Anis/Ladin Fractured LST conductive fracs @ 4772-4773m
Figure 8—Kick tolerance for 12 1⁄4 in. hole section

The team decided to run 9 5/8 in. casing to secure the long open hole which had been exposed for 49
days. The 9 5/8 in. casing was run and cemented successfully at 4496 mMD. Excess cement volume
pushed the measured top of cement 900 m higher than planned, since no losses occurred during the cement
job. This confirmed the suitability of product B, confirmed by cement bond log.
Despite the planned well depth was 5105 mMD, the 8 ½ in. hole was drilled to 6022 mMD. To ensure
pushing the well as deep as possible, a tapered drill string of 5 ½ in. and 5 in. were used in order to ensure
the rig pumps could handle the pressure while maintaining sufficient flow rate for proper hole cleaning.
The same LCM procedure as described earlier was applied to cure severe losses encountered in the 8 ½
in. hole. The summary of geomechanical events for the Stripfing T1 well is displayed in Figure (9). The
planned and actual pressure profiles are shown in Figure (10).
Figure 9—Drilling Summary Geomechanical Events

Loss Treatment Planning Phase
The operator had experienced losses in the naturally fractured limestone sections of all Stripfing T1’s
offset wells. In addition to using conventional granular LCM, the operator had also used barite pills and
cement to reduce losses. However, the highest success in curing the medium to severe losses (approxi-
mately 50% rate of success), had been achieved by pumping cross linking polymers pills.
The drilling fluids market is flooded with LCM products. The authors have knowledge to over 200
different products supplied by over 50 different companies including various cross linking polymers
packages. The CLP approach presented itself as the best choice early in the planning phase, if severe
losses were encountered. The ~ 50% success rate identified from offset wells was deemed to be too low
and hence initiated an evaluation process for alternative solutions. This low success rate for the cross
linking polymers could be due to a number of issues:
● Dilution in surface lines
● Incorrect temperature estimations
● Accelerator / retarder concentration
● Incorrect placement
The LCM evaluation process was aimed at identifying products that proved most effective in all types
of loss zones encountered:
Figure 10—Pore, mud weight and fracture gradient (plan versus actual)

For over a decade a Joint Industry Project has looked into wellbore strengthening. These techniques are
similar to lost-circulation techniques, but there are significant differences. Wellbore strengthening
techniques focus on avoiding loss, and moreover on increasing the apparent fracture gradient by sealing
the fracture and isolating the fracture tip to keep it from elongating further. In comparison, lost circulation
solely focuses on mitigation of losses.
The planning team looked at regions, where losses in natural fractured limestone were most frequent
within the oil industry, and how these losses were cured. It showed that drilling operations in the Middle
East had encountered the most serious challenges as far as lost circulation was concerned, and the Middle
East region was therefore used as a baseline. Reports indicated that drilling at shallow depth had
encountered losses in kartisifed, vugular or cavernous limestone and dolomite aquifer. To cure these
losses operators had employed cross linking polymers, LCM pills and cement squeezes. Cementing was
reported to be difficult, requiring stage tools, low specific gravity cementing slurries and several top-up
jobs. In the deeper formation the Middle East region is known to encounter thick porous carbonate
sections, which are naturally fractured (vertically) and renowned for both complete and partial loss of
returns during drilling.
The mechanism for losses in the limestone formations in the Middle East region was believed to
correlate with those expected on Stripfing T1 well. The combination of cross linking polymers, LCM and
cementing previously used to cure or control losses had reported only partial success. A local major
operator in Middle East region reported that two new fiber based products – A and B – had reduced lost
circulation significantly.
Evaluation process
There are no standard evaluation processes for the downhole performance of LCM products. Since the
fracture network and fracture width could not be established during the planning phase, two different loss
scenarios were considered (partial and total). In most cases partial can develop into total loss if not cured
successfully. The objectives of the evaluation were to:
1. Establish best preventive LCM products to reduce seepage and partial losses – the material should
be able to be pumped through downhole logging tools. Furthermore the concentration should only
have minimal contribution to the rheology profile.
2. Establish best LCM product and procedure to cure severe and total loss of returns during drilling.
The Stripfing T1 planning team first looked at using Aloxite disk of various sizes in a standard HTHP
fluid loss cell in the evaluation process; however this method did not differentiate sufficiently between the
products. This was partially as expected since none of the LCM products claim to control loss of filtrate
as such, but aim to strengthen the filter cake only. An earlier screening process had used pressure rated
transparent tubes filled with gravel sand and measured the invasion of mud into gravel sand. 20/40 gravel
sand was selected and pressure of 100 psi applied.
The transparent tube (Figure 11) was fitted with a cap at the bottom and filled with sand up to a
predetermined and marked level, above the sand fluid was poured and a top cap with a pressure gauge and
cylinder was screwed on. Pressure was then applied gradually in 20 psi increments up to a maximum of
100 psi. The fluid invasion was measured and recorded in each step. A total of 10 LCM products were
tested. The product giving the lowest invasion at the lowest concentration and with a particle size
distribution that allowed pumping through any downhole tool was selected as the best product to use.
Product A at a concentration of 20 kg/m3
was found to perform best. Product A repeatedly established a
a. Porous conglomerates (Aderklaa Conglomerate, Gosau Formation)
b. Heavily fractured limestone (Steinalmkalk, Gosau Formation)

tough and clear filter cake, Figure 12. The mud rheology was not affected by the above concentration of
Product A.
Two other products nearly matched the total invasion exhibited by Product A, but at a higher
concentration and with a significant contribution to the rheology profile.
In the selection test for the best LCM for losses above 6 m3
/hr, a particle plugging aperture, was used
but the Aloxite disk at the bottom was replaced by a set of slotted disks for separate testing. The openings
of the slotted disks were as follows; 500, 1000, 3000 and 5000 ␮.
At the bottom of the particle plugging aperture, a cap with a valve was fitted and the particle plugging
aperture was placed on a stand above a measuring cup. The base fluid plus the recommended product
concentration were then poured into the particle plugging aperture cell. The top cap, fitted with a pressure
gauge was screwed on and pressure applied in 100 psi increment every 5 minutes to a maximum pressure
of 500 psi. The intention was to simulate a hesitation squeeze.
Figure 11—Invasion Test, showing penetration of fluid into a standardized sand column at 100 psi overpressure
Figure 12—Product A filter cake

The predetermined selection criteria were defined as follows:
● Sealing without excessive filter cake on top of the disk
● The material mixed in mud should seal the slots as increasing pressure (up to 500 psi) was applied;
i.e. simulating a hesitation squeeze.
● LCM products should be visible on the low side of the disks.
● The blockage of the slots should NOT create an ЉexcessiveЉ plug on the Љapplied pressure sideЉ of
the disk, but the products should be clearly visible beneath the slotted disk; this would be regarded
as the ЉsqueezabilityЉ of the product.
It was the understanding from the start that the products for curing severe and total losses could not be
pumped through any downhole tool, but had to be pumped through a circulation sub in the BHA. Because
of the nature of the fractures – vugular and/or cavernous – it was thought that the successful pill
formulation would have to be placed by hesitation squeeze, and depending on the width of the fractures
probably more than one pill had to be placed to completely cure the losses.
All of the 12 products tested sealed the 500 ␮ and 1000 ␮ slotted disks, 3 products sealed the 3000 ␮
slotted disk. They were:
● A commonly used very fibrous LCM mixture
● A commonly used very fibrous LCM mixture ϩ sized calcium carbonate mixture
● Product B
For the first two formulations, with concentrations recommend by the suppliers, an excessive and thick
filter cake had developed on top of the slotted 3000 ␮ disk; there was no sign on the lower part of the disk
indicating that no product had been squeezed into the slot. The Product B formulation had a thinner filter
cake on the top of the slotted disk and large amount of the product was observed on the lower side of the
disk.
Only Product B sealed the 5000 ␮ slotted disk, again with a thin filter cake on the pressure side and
with a larger part of the product visible on the low side of the disk. Product B was selected for use on
Stripfing T1. The manufacturer had recommended a concentration of 125 - 210 kg/m3. This was reduced
to 115 kg/m3
due to concerns about pumpability.
Manufacturer of Product B’s recommended additional tests, see Figure 13, where only Product B was
able to create a filtercake and sealed the fractures, here ϩ/- 3000 to ϩ/- 10000␮.
Figure 13—Product B additional plugging test and Filter cake

Field Results
Product A was used to cure seepage and partial losses in 17 ½ in. hole. The manufacturer had
recommended adding the product into the active circulation system. Instead the operator pumped 10 m3
pills Љon the fly,Љ minimum twice per each drilled stand and this controlled both seepage and partial losses
up to a rate of 6 m3
/hr.
Product B was used to cure severe losses in 12 ¼ in. hole. Eleven severe losses incidents, up to a loss
rate of 50 m3
/hr were encountered in the limestone formations. A decision tree, as seen in (Figure 14)
determined what to pump in each case.
A very detailed spotting procedure for Product B was prepared in advance after discussion with the
manufacturer. Not adhering to the procedure for Product B resulted in down time.
Ten (10) Product B pills were pumped through a circulation sub and one (1) pill was pumped through
a bit with open nozzles. In the latter pill, the Product B concentration was reduced from 115 to 100 kg/m3
.
The detailed spotting procedure can be seen below:
i. Remove strainers (if any) from the following areas before pumping Product B pill
a. Rig and charge pump section
b. Rig pump discharge
c. Standpipe manifold
d. Drill pipe
ii. When losses occur, hold a Pre-job safety Meeting, and pull the bit 30 meters above the loss zone
to increase the probability of exposing the entire loss zone for treatment.
Figure 14—Lost Circulation Reaction Chart

iii. Premix Product B as follows:
iv. Flush the drill string with LCM free active mud, at least 1 ½ string volume, this to ensure bypass
ports on circulating sub are clear of any LCM.
v. If circulating sub used in the drill-string, break top drive and open (activate) circulating sub.
vi. Pump 5 m3
high viscous pill ahead (high viscous mud weight should be same as active mud) to
minimize dilution of the Product B pill concentration and to reduce mud pump loss prime.
vii. According to the loss rate, pump the Product B pill with 300 to 500 litres/minute pump rate and
follow the pill with 5 m3
high viscous spacer. Dedicate only one (1) pump and keep pumping until
the entire pill and 1-2 m3
of the high viscous spacer behind the pill are out of the string.
viii.With the string filled up with part of the spacer behind the pill, pull bit above the calculated top
of pill, or inside the casing shoe and flush the drill string with LCM free mud to ensure ports are
clear of any LCM Material.
ix. If circulation is regained, continue circulating using stage up rates to assist in squeezing the pill
into formation
a. If necessary perform a hesitation squeeze, staging pump from 50 to 300 psi
b. Keep annulus full at all times.
x. If full circulation is not regained, repeat Steps iv to ix.
xi. Note: When full circulation is established flush rig pump’s manifold and surface lines used for
Product B pill with LCM free mud to remove any Product B particles that could potentially plug
surface lines and BHA components.
xii. When surface lines are flushed, flush drill string. If a circulation sub is used, circulate minimum
of two drill string volume with LCM free mud prior to deactivating the circulation sub.
xiii.Drill/wash/ream slowly through product B pill at a rate of 20 mins/stand depending on resistance.
xiv.Circulate each stand 5 minutes before making a connection and monitor to avoid packing off
problems that may induce breaking down the formation again.
xv. Control the pump pressure at ~ 75% of the drilling pump rate to avoid packing off problems.
xvi.Once on bottom, circulate two bottoms up before returning to drilling.
Product A and B LCM proved to be efficient in a range of lost-circulation applications. The evaluation
process gave very conclusive results. The unknown was the nature and size of the actual fractures to be
encountered during the drilling phase. It was possible that the particle size distribution for both Product
A and Product B gave the best results, simply because of the testing equipment and test setup. However
the field results were also conclusive, seepage losses were cured by Product A, and the severe losses were
cured by Product B, and their respective particle size distribution in combination with the product
concentration, physical nature of the fibers cured the losses
Impact analysis
The effects of product A and product B were evaluated using resistivity images, created by 2 different
tools. Product A at 15 kg/m3
cured the losses in limestone fractures when the loss rate was less than 6
m3
/hr. Analyzing Formation micro-imager data, (Figure 15) conductive fractures were often interpreted
near loss zones. The same conclusion also applies to Product B and loss rates were up to 50 m3
/hr.

Formation micro-imager wireline logs were obtained in 17 ½ in. hole from 2485 mMD to 2968 mMD.
Resistivity imager LWD technology was run in 12 ¼ in. hole from 2990 mMD to 3898 mMD and
Formation micro-imager wireline logs were obtained from 3825 mMD to 4487 mMD. Over long interval
no bedding or other features could be identified due to lithology. Conductivity in those intervals is very
low. An overlap with Resistivity imager LWD is available for a short interval. Formation micro-imager
wireline logs were obtained in the 8 ½ in. hole from 4496 mMD to 5194 mMD.
The images recorded are all dependent on resistivity contrast. The Resistivity imager LWD typically
records and measures for 3 different depths of investigation. The vertical resolution is highly dependent
on resistivity contrast; is estimated to be about one inch. Laterally a total of 240 sectors are recorded. In
an ideal situation of 8 ½ in. caliper this results in a resolution of 0,1 in.
Fractures recorded will appear on the log depending on:
● Geometry (orientation in relation to the wellbore trajectory)
● Dimension
● Most important the fluid content they contain, since this determines the electrical properties of it.
High resistivity contrasts will always allow to record fractures of a relatively smaller aperture. Wireline
tools provide twice the resolution of LWD image. In the example provided it must be assumed that the
resistivity of pure limestone in the range of Ͼ 1000 ⍀.m. Typical resistivity of water base mud used 10
- 50 ⍀.m. Since all fractures recorded are only recorded once, at least ~ 9 m behind the bit it must be
assumed that they have already undergone some alternation if they are the cause of the losses. This
becomes even more true for wireline log data. It is not possible to perform a simple before and after
comparison to prove the effectiveness of the LCM used.
Figure 15—Example for a Wireline image log, depth markers are in meters. Static (left) and dynamic (right) image show suites of
fractures, interpreted as conductive

Fractures of significance which are connected to a discrete fracture network capable of absorbing large
quantities of drilling mud (up to 50 m3
) will appear on all 3 depths of investigation. Their appearance on
the log is reported by a black line.
The image logs available don’t allow to draw direct conclusions (visual proof) if the fractures were
closed by the LCM applied. However holistic approach can lead to this conclusion if the following facts
are considered:
● Accurate recording of the drilling depth when losses are encountered
● Quantifying these losses
● Recordings and interpretation of the image log at the depth of investigation
As a verification of the effectiveness of the LCMs deployed the image logs and losses versus depth
were also checked for sections without fractures. This test proved true in a majority of cases as well.
Cost Summary
Well integrity was challenged by continuous seepage to severe losses (up to 50 m3
/hr). The drilling fluid
costs doubled due to downhole mud losses (~ 3200 m3
), increasing from a planned cost of approximately
EUR 1.25 million to a final cost of EUR 2.2 million. The new LCM costs were less than 10% of the cost
of the overall volume of mud lost and allowed drilling ahead. The cost saving for not running and
cementing the 11 3/4 in. liner is approximately EUR 2.0 million (including the hole enlargement costs
prior running the liner).
Figure 16—Example for image log recorded by LWD, showing a conductive fracture @ 3823m, a depth where losses were recorded
nearby

Conclusions
1. Despite the short planning time and low quality of seismic data, the HPHT exploration well was
drilled to 6022 mMD successfully. Various simulations allowed the HPHT section to be extended
beyond conventional limits.
2. By deploying flexible well design, various technical challenges were successfully overcome
including an abnormally high pressure ramp, high unpredictable formation thicknesses, narrow
mud window, Severe losses, pore pressure of 820 bar and bottom-hole temperature of 171°C.
3. Wellbore instability problems for Gosau formation have been eliminated by using a new mud
system and following the recommended drilling and tripping practices.
4. To drill ahead in the 12 ¼ in. hole with these encountered severe losses and limited kick tolerance
volume would normally require running 11 ¾ in. liner to isolate the abnormal pore pressure from
the loss zone. In order to achieve that, extensive engineering work and real-time monitoring
assisted in improving drilling efficiency and decision making.
5. Safety regulations and following well control policies are essential components for drilling the
deep HPHT exploration well successfully.
Acknowledgments
The authors thank the management of both OMV Austria E&P and Drilchem for support and permission
to publish this paper. Special thanks go to Kaat Van Hecke and Wilhelm Sackmaier who trusted this
technology and allowed its use in several challenging environments.
We also gratefully acknowledge the support of Oliver Knoop for his assistance with the work on
geological overview, to all the operational personnel who have been responsible for putting the theory into
practice and Bjorn Ovrevik for his assistance with reviewing and proof reading the text.
Abbreviations
BHA Bottom Hole Assembly
BHCT Bottom Hole Circulating Temperature
BHST Bottom Hole Static Temperature
CBL Cement Bond Log
GEM Geomechanical Earth Model
HPHT High Pressure High Temperature
LCM Lost Circulation Material
LOT Leak off Test
LWD Logging While Drilling
mMD Meters of Measured Depth
MWD Measurement While Drilling
PP/FG Pore Pressure / Fracture Gradient
ROP Rate of Penetration
TD Total Depth
References
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Program: Evolving Strategy to Control Severe Losses in Deepwater Projects. Presented at SPE/IADC Drilling
Conference, Amsterdam, Netherlands, 19–21 February. SPE-79836-MS. http://dx.doi.org/10.2118/79836-MS

4. Sweatman, R., Wang, H., and Xenasis, H. 2004. 2004 Stabilization Increases Fracture Gradients and Controls
Losses/Flows During Drilling. Presented at the SPE Abu Dhabi International Conference and Exhibition, Abu Dhabi,
UAE, 10–13 October. SPE-88701-MS. http://dx.doi.org/10.2118/88701-MS
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in Fractured Limestone Formations, Offshore East Kalimantan, Indonesia. Presented at the SPE Asia Pacific Oil and
Gas Conference and Exhibition, Jakarta, Indonesia, 20–22 September. SPE-145763-MS. http://dx.doi.org/10.2118/
145763-MS
6. Vickers S.R., Hutton, A.P., Main, R., Jeffery, A., and Jackson, G.2010. Drilling Highly Fractured Limestone
Reservoirs: Is it a Particle Bridge Too Far?. Presented at the SPE Annual Technical Conference and Exhibition, 19–22
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