Economic benefits from using formate brines - Latest paper

Economic benefits from using formate brines - Good well performance and recovery of reserves

• “High production rates with low skin” *

• “ We selected formate brine to minimise well control problems

and maximise well productivity”*

* Quotes by Statoil relating to Kvitebjoern wells (SPE 105733)

Economic benefits from using formate brines

- More efficient and safer drilling

“ a remarkable record of zero well control incidents in all 15

HPHT drilling operations and 20 HPHT completion operations”

Better/safer drilling environment saves rig-time costs • Stable hole: see LWD vs. WL calipers in shale

•Elimination of well control* and stuck pipe incidents •Good hydraulics, low ECD

•Good ROP in hard abrasive rocks

* See next slide for details

Formate Brines : Allow fast solids-free drilling

Solids-free formate brines drill deep horizontal well sections much faster than muds like OBM – and cause less formation damage

Economic benefits from using formate brines - Improved well control and safety

• Elimination of barite and its sagging problems

• Elimination of oil-based fluids and their gas solubility problem

• Low solids brine Low ECD (SG 0.04-0.06) and swab pressures

• Inhibition of hydrates

• Ready/rapid surface detection of well influx

• Elimination of hazardous zinc bromide brine

- Drill-in and completing with formate brine allows open hole completion with screens

- Clean well bores mean no tool/seal failures or blocked screens

- Completion time 50% lower than wells drilled with OBM

“ fastest HPHT completion operation ever performed in North Sea (12.7 days)”

Economic benefits from using formate brines

- More efficient/faster completions

• No differential sticking

• Pipe and casing running speeds are fast

• Mud conditioning and flow-check times are short

• Displacements simplified, sometimes eliminated

Duration of flow back(minutes)

Fluid Gain (bbl)

30 0.8

15 0.56

20 0.44

30 0.56

Flow check fingerprint for a Huldra well

Economic benefits from using formate brines - Operational efficiencies

Economic benefits from using formate brines - Good reservoir definition if Cs present in fluid

• High density filtrate and no barite

• Filtrate Pe up to 259 barns/electron

• Unique Cs feature - makes filtrate invasion highly visible against formation Pe of 2-3 b/e

• LWD can “see” the filtrate moving (e.g. see the resistivity log on far right – drill vs ream

• Good for defining permeable sands (see SAND-Flag on log right )

• Consistent and reliable net reservoir definition from LWD and wireline

Economic benefits from using formate brines - Good reservoir imaging

• Highly conductive fluid

• Clear resistivity images

• Information provided: - structural dip - depositional environment - geological correlations

Formate brines – Summary of economic benefits provided to users

Formate brines improve oil and gas field development economics by :

Reducing well delivery time and costs

Improving well/operational safety and reducing risk

Maximising well performance

Providing more precise reservoir definition

SPE 165761 (2012) “ Experience with Formate Fluids for Managed Pressure Drilling and Completion of Sub-Sea Carbonate Gas Development Wells”

Managed pressure drilling and completion of fractured carbonates with formate brine

• Petronas - Kanowit field – 2 sub-sea gas wells

• Managed pressure drilling in fractured carbonate with K formate brine improved economics by:

- Minimising fluid losses

- Reducing fluid cost (use K formate instead of Cs formate)

- Improving production by 50%

- Eliminating need for stimulation (no acidising)

Kanowit SS-1 : Production profile from start-up - natural clean-up – no stimulation

•100 MMscfd gas and 4,000 bpd condensate after 5 hours

• >150 MMscfd gas and > 6,000 bpd condensate after 9 hours

Kanowit SS-1 : Multi-rate well test results

Both wells can produce > 150 MMscfd gas and > 6,000 bpd condensate

The maximum potential flow rate figures are 50% higher than the technical potential predicted in the original field development plan.

MRT measurements on well SS-1 before acidizing (Mahadi et al, 2013)

MRT Test Choke size

(/64)

Well Head

Pressure

(psi)

Gas Flow rate

Choke correlation

(MMscfd)

Gas Flow rate

Sonar

(MMscfd)

PDG Pressure

(psi)

PDG Temp

(oF)

1 112 2874.4 159.16 147.61 3857.0 252

2 88 3273.0 111.85 108.76 3932.2 252

3 64 3476.8 63.46 64.51 3978.5 251.7

4 40 3560.5 25.84 28.01 3998.8 250.1

OPERATOR LOCATIONPacker Fluid

(ppg)BHT (°C)

BHT (°F)

Start Date

End Date

Comments

Devon WC 165 A-7 8.6 KFo 149 300 1/2005

Devon WC 165 A-8 8.6 KFo 149 300 1/2006

DevonWC 575 A-3

ST29.5 KFo 132 270 5/2005

WOG/Devon MO 862 #1 12.0 NaKFo 215 420 4/2005 5/2006Well P&A – H2O production – G-3 in excellent condition

BP/Apache HI A-5 #1 11.5 NaKFo 164 350 2/2002 4/2008Well P&A - Natural depletion – S13Cr in excellent condition

ExxonMobil MO 822 #7 12.0 NaKFo 215 420 2001

EPL ST 42 #1 11.5 NaKFo 133 272 2006

EPL ST 41 #F1 13.0 NaKFo 105 222 2006

EPL EC 109 A-5 11.5 NaKFo 121 250 2006

EPL ST 42 #2 12.8 NaKFo 132 270 2006

DominionWC 72 #3

BP110.0 NaFo 121 250 2006

EPLWC 98 A-3

ST112.7 NaKFo 153 307 2006

EPL WC 98 A-3 10.8 NaKFo 154 310 2007

Formate brines as packer fluids in GOM

• 177ºC, 14,000 psi

• S13Cr tubing failed from CaCl2 packer fluid

• Well worked over and re-completed with Cs formate

• 1.4 g/cm3 Na/K formate used as packer fluid

• Tubing retrieved 6 years later

• Tubing was in excellent condition.

BP High Island – Formate brine used as a packer fluid for 6 years