2009May/JuneSafety and ESG

Can UBD flaring reduce global CO2 emissions?

By Dave Elliott, John Ramalho, Shell E&P

One of the perceived blockers for underbalanced drilling (UBD) operations is the necessity for flaring gas in most operations. As the world becomes more aware of the impact of CO2 emissions, oil and gas producers are implementing flaring reduction targets or, in some cases, flaring bans as a key component in their corporate strategies.

Project teams often argue that, due to flaring requirements, UBD is not aligned with corporate directives and is not environmentally acceptable. Thus the technology is eliminated as an option when finalizing field development plans.

As the UBD industry has matured, the use of UBD to increase production and reserve recovery has resulted in a reduction of the number of wells needed to develop fields. Reservoir characterization from UBD has been used to better target wells in the reservoir, reducing the chances for “junk wells” with poor or no production. UBD is also used as an enabler to slim down wells with reduced steel requirements and to drill faster with reduced rig emissions.

This article will evaluate the trade-off of increased CO2 emissions from UBD flaring against reduced CO2 emissions from fewer required wells, reduced steel requirements and reduced rig time from the perspective of several Shell case studies. The following conversions and grounding data will be used to help visualize CO2 emissions from various sources and to help understand quantities and emission reduction trade-offs:

  • Using 1 cu m of diesel fuel generates 2.5 tonne of CO2.
  • Producing 1 tonne of steel requires 3.2 tonne of CO2 emissions.
  • Flaring 1,000 standard cu m of gas generates 2.0 tonne of CO2.
  • A 4,000-hp land rig generates as much CO2 as a power plant supplying electricity to 2,000 people.
  • Steel production in China produces approximately 520 million tonne of CO2 annually, or approximately 1.5% of global CO2 emissions.
  • Total oil and gas flaring produces 187 million tone of CO2 annually. This is approximately 0.6% of global fossil fuel-based CO2 emission.

In 2001, Shell adopted a strategy of global UBD implementation and set up a team to assist with candidate selection and support. Since that time, the company has drilled approximately 700 UBD wells, more than any other super major E&P company or major resource holder. Results from the large projects’ (statistically valid) operations can be evaluated to determine where arguments can be made for reduced well numbers or well design in a field development.

The company is obtaining value from UBD in three overall categories:

  1. Reduced drilling problems.
  2. Reduced formation damage.
  3. Dynamic reservoir characterization.

Reduced drilling problems include value for less nonproductive time (NPT) and higher ROP, which reduces well construction time. Reducing well construction time leads to a direct reduction of diesel consumption for rig operations and logistics, thus CO2 emissions. Reduced drilling problems from a UBD perspective can also mean being able to drill deeper through a long gas column as an enabler to slim down the well’s casing plan. Drilling smaller top hole sizes can improve their ROP and eliminate time for casing running. More importantly, from a CO2 emission perspective, significantly lower steel requirements can be achieved.

It has long been accepted that UBD can reduce formation damage, which can significantly improve production and recovery efficiency per well. Shell, however, does not drill the same well designs using UBD as with overbalanced (OBD) operations. Well lengths in the reservoir and even the number of multilaterals drilled are changed during UBD operations using real-time reservoir characterization data to improve production.

It is therefore, from a practical perspective for this article’s scope, difficult to differentiate increased production from reduced drilling damage, and increased production from real-time reservoir characterization. Fortunately, from a CO2 perspective, the reason UBD wells produce more is not important. What’s important is the statistical validity of the comparison of the number of wells that would have been required if OBD had been deployed compared with the number of wells with UBD for the same volume of gas or oil production.

Therefore, in this evaluation, the value from reduced drilling damage and real-time reservoir characterization will be combined, only focusing on a comparison of overall production between UBD and OBD operations.

Case Study

Offshore tight gas development wells
Approximately 40 offshore tight gas development wells have been drilled from jackups to a depth of 3,000 m with along-hole lengths up to 5,500 m deploying horizontal open-hole completions. These wells took, on average, 90 days to drill. The reservoirs have low matrix permeability and are highly susceptible to formation damage due to high hairy illite concentrations. They also require well contact with natural fractures or “sweet spots” to achieve optimum rates.

Unfortunately, a high degree of uncertainty exists as to the location of sweet spots. UBD reservoir characterization and drilling damage reduction was deployed with contingency multilateral legs with a target well capacity of 2 million cu m/day. Approximately 90% of the 40 wells were drilled UBD to flare, using draw-down control to minimize the flare rates. Where possible, wells were drilled with the gas produced during UBD recovered down the pipeline.

UBD flaring CO2 emission:

  • Average flaring during UBD: 30 days.
  • Average flare rate during UBD: 200,000 cu m/day.

Onshore fractured carbonate development oil wells with a thin oil rim
Approximately 30 fractured carbonate oil wells have been drilled in Middle East fields with thin oil rims using UBD. UBD was deployed for damage reduction and reservoir characterization to identify water production up fractures under dynamic flowing conditions. Subsequent completions in the wells shut off the water using UBD data to target the isolation of water-producing fractures with swelling elastomer liners. Wells average 1,100 m TVD with total well lengths of 2,000 m. They took an average of 28 days to drill with eight days of UBD flaring.

UBD flaring CO2 emission:

  • Average flaring during UBD: 8 days.
  • Average flare rate during UBD: 32,000 cu m/day.

Onshore tight gas development wells
Shell has drilled over 300 UBD development wells in a North American tight gas field. Wells are drilled vertically to a depth of around 4,200 m. These wells have a very long gas column of approximately 1,800 m. UBD is deployed to facilitate slimming down the well casing design, allowing penetration to TD with a 6-in. hole using one fewer casing string that would otherwise have been needed to prevent exceeding the fracture gradient in the gas column.

Additional value is delivered through higher ROP and reduced NPT from fluid losses. Well numbers and comparison to competitor offset wells in the same structure, which do not deploy UBD, enable accurate estimation of time and steel requirement savings. Draw-down control is used to minimize flare rates, with mud weights designed to give “at balanced” conditions during drilling and underbalanced conditions during connections.

UBD flaring CO2 emission:

  • Average flaring during UBD: 10 days.
  • Average flare rate during UBD: 14,000 cu m/day.

Conventional Well construction

As stated in the introduction, CO2 emissions from “unseen” sources of conventional well construction can be very significant. To compare these CO2 emissions with the three projects above, emissions will be calculated with the corresponding well design’s steel requirements, as well as diesel consumptions for rig operations and logistics.

Offshore tight gas development wells

Estimate details:

  • Estimated 8 tonne or 10 cu m/day rig diesel.
  • Logistics diesel for daily transport to rig and rig move: estimated 5 cu m/day.
  • Well design is a three casing string well to 5,500 m with 13 3/8-in. to 7-in. casing set at 4,000 m, open-hole completions and 3 ½-in. tubing.
  • 90 days rig time per well.

Onshore fractured carbonate development oil wells with a thin oil rim

Estimate details:

  • 1,800-hp engines: estimated 6 cu m/day rig diesel.
  • Logistics diesel for daily transport to rig and rig move: estimated 4 cu m/day diesel.
  • Well design is a three casing string well to 2,000 m with 13 3/8-in. to 7-in. liner set at 1,700 m, open-hole completions (some with water shut-off liners) and 3 ½-in. tubing.
  • 30 days rig time per well.

Onshore tight gas development wells

Estimate details:

  • 2,000-hp engines: estimated 6 cu m/day rig diesel.
  • Logistics diesel for daily transport to rig and rig move: estimated 4 cu m/day diesel.
  • Well design for analogue non-UBD wells is a four casing string design with 9 5/8-in. to reservoir top at 2,400 m, a 7-in. liner set halfway through the gas column and 4 ½ in. to TD at 4,200 m.
  • Well design for UBD wells is a three casing string design with 7-in. to reservoir top at 2,400 m and 4 ½ in. to TD at 4,200 m.
  • 30 days rig time per UBD well and 70 days for non-UBD wells. However, for this article, only 15 days of savings (conservative) will be assumed attributed to UBD, with the remainder attributed to other differences (drilling procedures, mud type and bits).

Neutral Emissions Point?

In order to compare the impact of CO2 emissions from UBD flaring with conventional operations, the process of calculating the neutral point of each project will be used. Shell uses this approach as a high-level screening tool when considering if UBD may be economically justified.

The increased production from UBD often cannot be accurately calculated without detailed reservoir modeling, including the impact of non-uniform damage. Therefore, the company calculates the cost of UBD operations and compares these costs with an overbalanced well’s cost estimate. This ratio can then be used to discuss the probability of achieving the needed production uplift as compared with analogue data.

A similar approach will be used to evaluate CO2 emissions. All three projects have the potential to reduce well numbers or well construction time or to slim wells down. The CO2 neutral point, as to what percentage well numbers need to be reduced to recover similar oil and gas for each project, will be calculated. Similarly, the CO2 neutral point to slower and fatter well designs can be calculated.

Offshore tight gas development wells

As calculated, CO2 emissions from flaring emitted 12,000 tonne of CO2 per well, whereas overbalance construction of the well emitted only 5,150 tonne. This is, however, not the complete picture. Flaring was done on UBD wells drilled before the platforms could be installed to recover subsequent UBD gas down the pipeline or until equipment designs enabling gas recovery could be designed. Towards the end of the project, gas recovery had been implemented where possible. As such, UBD flared wells should be considered as “appraisal” wells, the drilling of which enabled sufficient clarity of well productivity to justify platform construction.

This project is probably CO2 neutral. The ratio of production from the UBD wells is roughly balanced to the production we would have had if we had drilled 3.3 times as many overbalanced wells.

Onshore fractured carbonate development oil wells with a thin oil rim
CO2 emissions from flaring emitted 520 tonne of CO2 per well. CO2 emissions from diesel and steel consumption were 1,260 tonne per well.
Increased production from this project probably exceeds its 1.4 UBD CO2 neutrality ratio. However, planning is under way to compress and capture flared gas on expected high GOR wells that will reduce project CO2 emissions. The project is expected to be similar to operations in the Southern North Sea, where gas recovery is justified after an appraisal period of flaring to prove UBD value. With application of gas recovery, this project is expected to quickly become even more positive for UBD CO2 emission reduction.

Onshore tight gas development wells

Flaring from UBD emits 280 tonne of CO2, which compares with a savings of CO2 emissions of 820 tonne for less diesel and steel. Note that, in this case, there is no need to calculate a CO2 neutral point, as a comparison can be made of the different well construction practices with no uncertainty of production uplift. Total CO2 from the non-UBD wells is 2,258 tonne per well, and total CO2, including flaring from the UBD wells, is 1,718 tonne, resulting in a reduction of global CO2 emissions of approximately 25%.

This reduction is shown Figure 2, where UBD with current flare rates reduce the overall carbon footprint of the project by 55,000 tonne of CO2 per 100 wells. However, increased awareness of CO2 management is resulting in flare gas meter installation and improved draw-down control to minimize flared volumes. Figure 3 shows the targeted impact, further reducing the CO2 carbon footprint to 75,000 tone per 100 wells.


  • UBD flaring and conventional well construction emits high volumes of CO2.
  • Engineers involved in well operation design and field development planning should consider CO2 emissions from all sources when evaluating opportunities to reduce CO2 emissions. Corporate environmental initiatives must be flexible enough to allow optimization of CO2 reduction. In some cases, a “no flaring” policy may make us feel good, but may result in increased CO2 emissions.
  • Limited UBD flaring can, in some cases, reduce overall project CO2 emissions. Projects designed to collect dynamic reservoir flow information are the most likely to reduce CO2 emissions through reduced well numbers during the development phase and minimization of flaring from well testing and stimulation cleanup. UBD at the beginning of a project in the exploration and appraisal phases has the maximum chance of reducing project CO2 emissions.
  • Oil well UBD has a lower threshold to achieve CO2 reductions than UBD gas well due to the reduced gas flare rates.
  • Even in projects where UBD flaring will result in reduced overall CO2 emissions, efforts to reduce flared volumes should be undertaken. These include draw-down control to reduce flare rates and, where possible, gas recovery. On projects with high UBD dynamic reservoir characterization value, an optimized decision is needed to determine when sufficient understanding has been achieved to stop UBD operations and exploit the information through operations that do not involve flaring.

This article is based on a presentation at the 2009 IADC/SPE Managed Pressure Drilling & Underbalanced Operations Conference & Exhibition, 12-13 February, San Antonio, Texas.

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