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Awang Pon, M Zaim (Dialog Energy Sdn. Bhd.) | Hongmei, Gao (Dialog Energy Sdn. Bhd.) | Chee Hui, Sim (Dialog Energy Sdn. Bhd.) | Abdul Aziz, Shahrizal (Dialog Energy Sdn. Bhd.) | Abdulhadi, Muhammad (Dialog Energy Sdn. Bhd.) | Van Tran, Toan (Dialog Energy Sdn. Bhd.) | Anuar, M Azlan (Halliburton Bayan Petroleum) | Jacobs, Steve (Halliburton Bayan Petroleum) | Munandai, Hasim (PETRONAS Carigali Sdn. Bhd.) | Khalid, Aizuddin (PETRONAS Carigali Sdn. Bhd.) | Kumar, Ashok (PETRONAS Carigali Sdn. Bhd.)
Maturing a secondary recovery project in an offshore multi-fault complex reservoir is challenging because considerable investment is required, especially in a low oil price environment and/or when the asset can no longer produce. However, an 85% reduction in cost with no reduction in reserves was achieved for such a reservoir through de-risking the opportunity and revising the development concept, allowing the project to be sanctioned during a low oil price environment.
A water injection project with an estimated cost of 165 MMUSD was initially envisaged during the feasibility stage to increase the oil recovery of a depleted reservoir, and contractual expectations were agreed accordingly. This is due to the availability of seawater offshore and water injection being the standard improved recovery approach in the region. Without adhering to the familiarity, a reservoir simulation study was performed comparing multiple options of secondary recovery. The reservoir simulation indicated that gas injection would provide higher incremental recovery while the investment can be significantly reduced by utilizing the existing gas lift system as a gas injection system.
Several improved oil recovery schemes were evaluated with the history matched dynamic model to address the depleted energy. This includes water dumpflood, water injection, and gas injection with recovery factors of 32%, 56%, and 58%, respectively, in comparison to the depletion drive recovery factor of 30%. The gas injection scheme provides the highest recovery factor and expected fastest response and thus was prioritized as the main focus over water injection. The existing gas compressor with ullage, gas source from current associated gas production, and existing idle wells are key enablers for the project. The existing assets also enable the acceleration and further de-risking by a pilot gas injection before drilling infills.
The paper highlights the numerous examples of cost-saving initiatives while maximizing the oil recovery from the reservoir. This value-focused approach enabled the project to be sanctioned during a period where most offshore improved recovery projects were abandoned due to the low oil price.
Abdulhadi, Muhammad (Dialog Group) | Tran, Toan Van (Dialog Group) | Chin, Hon Voon (Dialog Group) | Jacobs, Steve (Halliburton) | Suggust, Alister Albert (PETRONAS) | Usop, Mohammad Zulfiqar (PETRONAS) | Zamzuri, Dzulfahmi (PETRONAS) | Dolah, Khairul Arifin (PETRONAS) | Abdussalam, Khomeini (PETRONAS) | Munandai, Hasim (PETRONAS) | Yusop, Zainuddin (PETRONAS)
The first successful natural dump-flood in the Malaysian offshore environment provided numerous lessons learned to the operator. The minimal investment necessary for implementing the dump-flood coupled with the lack of recompletion opportunities in the subject wells suggested that direct execution without spending on expensive data gathering activity and extensive reservoir study makes more sense from a business point of view. A similar oil gain compared to a water injection project can be achieved at a significantly lower cost of USD 0.01 to 0.15 million in an offshore environment through dump-flooding.
The existing oil producers in the depleted reservoirs in Field B were originally completed and successfully drained oil from in a high-pressured watered-out reservoir below, making it an ideal dump-flood water source. The dump-flood was initiated by commingling the target and water source reservoir through zone change, allowing water to naturally cross-flow into the pressure depleted target reservoir. Once a memory production logging tool (MPLT) confirmed the cross-flow, the offtake well was monitored to determine the impact of the dump-flood and produce once the pressure was increased. Minimal investment was necessary because the operations were executed using slickline. The reservoir model will be calibrated once the positive impact of dump-flood is realized in the offtake well.
The first natural dump-flood in Reservoir X-2 has successfully produced 0.29 MMstb as of August 2018 with 600 BOPD incremental oil gain. The incremental recovery factor (RF) from the first dump-flood is predicted to be from 5 to 8%. Based on this success, it was decided to replicate the dump-flood project in other depleted reservoirs with Reservoir X-2 as an analog. Four reservoirs were subsequently identified, each with an estimated operational cost of approximately USD 0.01 million and potential incremental reserves of 0.10 to 0.20 MMstb per reservoir. The minimal investment necessary, the idle status of the wells and reservoirs, and the potential incremental reserves suggested that it is more appealing to proceed with implementing the dump-flood without undergoing an extensive and costly reservoir study. With reservoir connectivity being important to the success of dump-flooding, a more cost-effective approach would be to confirm the connectivity by monitoring the offtake well after the dump-flood is initiated. This approach provides more value because the cost of interference or pulse testing is significantly more expensive than the cost of the dump-flood itself while reservoir connectivity was already indicated as likely by geological data (map and seismic). Through a value driven approach, these dump-flood opportunities become more economically viable, allowing the operator to prolong the life of the assets and maximize the field profit.
This paper discusses using a value driven and business approach to implement the dump-flood in a mature field. Valuable insight into the business and technical considerations of implementing dump-floods are described, which are relevant to the industry, especially in today's low margin business climate.
Abdulhadi, Muhammad (Dialog Group Berhad) | Tran, Toan Van (Dialog Group Berhad) | Chin, Hon Voon (Dialog Group Berhad) | Jacobs, Steve (Halliburton) | Wahid, Muhammad Izad Abdul (PETRONAS) | Usop, Mohammad Zulfiqar (PETRONAS) | Zamzuri, Dzulfahmi (PETRONAS) | Dolah, Khairul Arifin (PETRONAS) | Abdussalam, Khomeini (PETRONAS) | Munandai, Hasim (PETRONAS) | Yusop, Zainuddin (PETRONAS)
Infill Well B-23, which was recently drilled in the CIII-2 reservoir located in the Balingian Province, experienced a rapid pressure and production decline. The production decreased from 2,200 to 600 BLPD within 1 year. Analysis of the permanent downhole gauge (PDG) data revealed that Well B-23 production was actually influenced by two other wells, B-20 and B-18, each located 2,000 ft away. This paper discusses the ensuing analysis and optimization efforts that helped reverse the Well B-23 pressure decline and restored its production to 2,200 BLPD.
Based on the typical causes of rapid production and pressure decline, operators initially believed Well B-23 was located in a small, separate compartment compared to Wells B-18 and B-20. Additionally, the Well B-23 behavior differed significantly from Wells B-18 and B-20. PDG data analysis provided clear evidence of well interference despite the significant distance between the well locations. Changes in the other wells immediately affected the Well B-23 pressure, thus leading to the conclusion that production from Wells B-20 and B-18 impeded the pressure support for Well B-23. To optimize Well B-23 production, Well B-20 was shut in while Well B-18 was produced at a reduced rate because of a mechanical issue.
The optimization initially resulted in more than 500 BOPD incremental oil from Well B-23. The well pressure decline was reversed, with PDG data showing a continuous increase of bottomhole pressure (BHP) despite an increase in the production rate. Subsequently, production was fully restored from 600 to 2,200 BLPD, and reservoir pressure returned to its predrill pressure. Going forward, the optimum withdrawal rate from the CIII-2 reservoir will be determined to ensure maximum oil recovery from both Wells B-18 and B-23. The case study proved the significant benefit of PDG data, which helped identify well interference as the actual cause of the rapid decline in Well B-23, instead of a reservoir or geological issue. Through in-depth analysis and thorough understanding of the reservoir, the operator restored what initially appeared to be a poor well to full production.
This case study shows the clear and strong effect of well interference and highlights how the subsequent results of the optimization effort were rapidly obtained. A comprehensive understanding of the reservoir behavior could not have been achieved at minimum cost without the pair of PDGs installed. The analysis and lessons learned from the Well B-23 PDG data provide valuable insight regarding the impact of well completions to the field of reservoir engineering.
Abdulhadi, Muhammad (Dialog Group Berhad) | Kueh, Pei Tze (Dialog Group Berhad) | Abdul Aziz, Shahrizal (Dialog Group Berhad) | Mansor, Najmi (Dialog Group Berhad) | Tran, Toan Van (Dialog Group Berhad) | Chin, Hon Voon (Dialog Group Berhad) | Jacobs, Steve (Halliburton Energy Services) | Muhd. Fadhil, Imran (PETRONAS Carigali Sdn. Bhd.) | Suggust, Alister Albert (PETRONAS Carigali Sdn. Bhd.) | Usop, Mohammad Zulfiqar (PETRONAS Carigali Sdn. Bhd.) | Ralphie, Benard (PETRONAS Carigali Sdn. Bhd.) | Dolah, Khairul Arifin (PETRONAS Carigali Sdn. Bhd.) | Abdussalam, Khomeini (PETRONAS Carigali Sdn. Bhd.) | Munandai, Hasim (PETRONAS Carigali Sdn. Bhd.) | Yusop, Zainuddin (PETRONAS Carigali Sdn. Bhd.)
It is a common practice to run a contact-saturation log to confirm the oil column prior to oil gain activities such as adding perforations or infill drilling. From 2012 to 2017, a total of eight logging jobs were executed in Field B which were subsequently followed by oil gain activities.
The eight contact-saturation logging jobs were comprised of pulse-neutron logs in both carbon-oxygen (C/O) and sigma mode. The logs were run in varied well completions targeting thirteen different zones. Four logs were run in single tubing strings while the remaining four were in dual string completions. Certain target zones were already perforated while others had completion accessories such as a blast joint or integrated tubing-conveyed perforating (iTCP) guns across them. Eight of the target zones were later add-perforated while two were used to mature infill well targets.
Four of the seven add-perforations results were consistent with the logging results. One of the successful logs clearly indicated that the oil column had migrated into the original gas cap. Of the two infill wells drilled, only one was successful. These case studies in Field B indicate that in conditions of open perforations, trapped fluid across the annulus, and in low resistivity sand, distinguishing between original and residual saturation is difficult with pulse-neutron log. The log measurement was significantly affected. The most obvious lesson learned was that perforating and producing the reservoir would be the best method to confirm the potential oil gain. From a value point of view, it would have been more economical to perforate the zone straightaway if the oil gain activity had similar cost to the logging activity. The lessons learned also helped to establish clear guidelines in Field B on utilizing contact-saturation logs in the future.
The paper seeks to present the logging results, subsequent oil gain activities, and lessons learned from the contact-saturation logging in Field B. These lessons learned will be applicable in other oilfields with similar conditions to improve decision making in the industry.
Abdulhadi, Muhammad (Halliburton Bayan Petroleum) | Kueh, Pei Tze (Halliburton Bayan Petroleum) | Zamanuri, Aiman (Halliburton Bayan Petroleum) | Thang, Wai Cheong (Halliburton Bayan Petroleum) | Chin, Hon Voon (Halliburton Bayan Petroleum) | Jacobs, Steve (Halliburton Bayan Petroleum) | Suggust, Alister Albert (PETRONAS Carigali Sdn. Bhd.) | Zaini, Ahmad Hafizi Ahmad (PETRONAS Carigali Sdn. Bhd.) | Jamel, Delwistiel (PETRONAS Carigali Sdn. Bhd.) | Dolah, Khairul Arifin (PETRONAS Carigali Sdn. Bhd.) | Munandai, Hasim (PETRONAS Carigali Sdn. Bhd.) | Yusop, Zainuddin (PETRONAS Carigali Sdn. Bhd.)
In the recent low oil price environment, a cost-effective solution was proposed to use through tubing bridge plugs to perform water-shut-off (WSO) in an offshore field. The solution consisted of using slickline to set a plug with a high expansion ratio followed by a cement dump. After three WSO jobs in different wells, the method has successfully proven itself. Watercut was reduced from 100% to 0% with a minimal cost of only USD100,000.
The through tubing bridge plug used is capable of passing through 2-7/8-in. tubing and expanding into 9-5/8-in. casing. After running a Gamma-Ray log, the plug was set across the perforation interval to give the anchor contact with a rough casing surface. The top of the plug, however, was above the perforation interval and became the base for cement. Cement was then continuously dumped on top using a slickline dump bailer in a static condition until the designed cement height was reached. Static conditions ensured no movement of cement during operation. The plug differential pressure limit is directly proportional to the cement height.
The first WSO job was a complete success with watercut reduced from 100% to 0%. The second job however, was partially successful as the cement dump was not completed due to unexpected appearance of a hold-up-depth (HUD). The HUD was created by leftover cement which had accumulated at the end of the tubing. Despite the setbacks, the end result was successful in reducing water production from 1000 bwpd to 200 bwpd. The third job faced a completely different problem. The original plug fell off deeper into the well after it was set. To rectify the situation, a second plug was set at the target interval. Despite the successful execution, there was no change in watercut after the well was brought back online. Since the same method was proposed for another upcoming well, Memory-Production log (MPLT) coupled with Temperature-Noise log was performed to assess the effectiveness of the WSO. The log results confirmed that the WSO was successful and the post job water production was caused by channeling behind the casing. The results so far concluded that the through tubing bridge plug WSO method was both reliable and cost-effective. It is exceptionally suitable for zones located at the bottom of a well and can be deployed using slickline.
The paper provides valuable insight to a WSO solution which should be a first-choice option due to its relatively inexpensive cost and high reliability. The solution has proven to provide tremendous cost saving for production enhancement activity.
Abdulhadi, Muhammad (Halliburton Bayan Petroleum) | Mansor, Mohd Najmi (Halliburton Bayan Petroleum) | Amiruddin, Nurul Azrin (Halliburton Bayan Petroleum) | Tran, Toan Van (Halliburton Bayan Petroleum) | Jacobs, Steve (Halliburton Bayan Petroleum) | Abd Wahid, Muhammad Izad (PETRONAS Carigali Sdn. Bhd.) | Usop, Mohammad Zulfiqar (PETRONAS Carigali Sdn. Bhd.) | Zamzuri, Mohd Dzulfahmi (PETRONAS Carigali Sdn. Bhd.) | Dolah, Khairul Arifin (PETRONAS Carigali Sdn. Bhd.) | Munandai, Hasim (PETRONAS Carigali Sdn. Bhd.) | Yusop, Zainuddin (PETRONAS Carigali Sdn. Bhd.)
Reservoir X-7, a watered-out reservoir in Field B, was successfully revived by perforating the original gas-cap zone to maximize oil recovery, which increased the recovery factor (RF) from 40% to 46%, resulting in approximately 2,300 BOPD through multiple perforations.
Maintaining the oil column sandwiched between gas and water is the standard practice to maximize oil recovery in a strong water-drive reservoir. Despite having a strong aquifer and a thick gas cap, Reservoir X-7 has produced continuously for 30 years without any gas reinjection. The reservoir was producing at 99% watercut, indicating the original oil column was already swept. Subsequent material balance study and saturation log results confirm that oil migrated into the original gas cap. Given the reservoir condition, an unconventional approach was proposed to produce the oil column through the original gas-cap zone.
The first gas-cap perforation for Well B-07 successfully produced 500 BOPD, so it was decided to perform three additional perforations (additional perforations) for Wells A-01, B-12, and B-16, which were successful with a total 2,000 BOPD oil gain from the three wells. Subsequent additional perforations was performed in Well B-07 after the original additional perforations watered out. However, the new additional perforations and subsequent ones in Well B-11 resulted in gas rather than oil. Both wells were shut in. Once the new perforations are watered out, the remaining oil potential in Reservoir X-7 will be confirmed by reopening well B-07 and B-11 until either oil or water is produced. The approach has so far provided approximately 2,300 BOPD of incremental oil production, extending well life by more than 24 months and allowing the RF to increase from 40% to 46%. It delivered encouraging results and opened up opportunities for other reservoirs.
This paper provides valuable insight into the case study and lessons learned in terms of maximizing oil recovery using original gas-cap perforation. This approach is highly recommended as the production enhancement method for maximizing oil recovery, particularly in mature fields with similar reservoir conditions.
In the late 1850s, the whaling industry was in a veritable boom in the town of Lahaina on the Hawaiian island of Maui. Business was great, and many in the whaling industry believed that increased demand would continue for decades to come. But in 1859, oil was discovered in Titusville, Pennsylvania with a well drilled by Edwin Drake. The rest is history.
That was 150 years ago. A small but increasing number of people around the world believe we are on a similar course, except this time it is the petroleum industry that might be threatened. As with any emerging technology, critical challenges must be overcome and a significant effort lies ahead to convince a world of skeptics that a new source of energy has been discovered and will be important.
The potential new source of energy is low-energy nuclear reactions (LENR). With any discussion of a new technology, caution is advised. The world of LENR is filled with mystery, contradiction, gross speculation, misinformation, slippery timelines, and skepticism that sometimes spill over into outright denial. Healthy skepticism on LENR (or any new technology) is a good thing, but so is an open mind. If LENR is for real—and many well-qualified physicists believe it is—it will not only change the petroleum industry, but also significantly affect almost every aspect of our world. Some call it “the new fire.”
In 1989 at the University of Utah, Stanley Pons and Martin Fleischmann announced they had discovered a cold fusion process that would ultimately result in cheap, limitless energy. The outcome from these cold fusion efforts became widely known and well documented, primarily because other researchers were unable to replicate the results from the initial experiments. Cold fusion was (and is) viewed as impossible by many in the scientific community. Although the research did not cease, it was largely ignored. For the past 20-plus years, a small number of scientists have been diligently working on what could eventually become a hugely disruptive technology.
According to New Energy Times, “LENRs are weak interactions and neutron-capture processes that occur in nanometer-to-micron-scale regions on surfaces in condensed matter at room temperature. Although nuclear, LENRs are not based on fission or any kind of fusion, both of which primarily involve the strong interaction. LENRs produce energetic nuclear reactions and elemental transmutations, but do so without strong prompt radiation or long-lived radioactive waste.” (“Strong interaction” and “weak interaction” refer to the strong nuclear force and the weak nuclear force, which—along with electromagnetic force and gravity—make up the four basic forces in nature.)
Editor’s note: This is the third and final installment of a multipart series examining key upstream technology uptake challenges in the oil and gas industry, and the reasons for the lack of accelerated acceptance of viable technologies needed to exploit increasingly challenging drilling and production environments.
Similar to the managed pressure drilling (MPD) article published in the February JPT and the seismic while drilling (SWD) article in March, a permanent downhole monitoring (PDM) survey was conducted among SPE readership around the world. In total, about 1,500 SPE members responded to the survey. The majority of the respondents were operators (64%) and technology providers (13%).
Unlike the previous two technologies analyzed, PDM generally has a higher level of acceptance among operators because it has been on the market for a longer time, and because significant reliability and performance improvements have occurred over the past several years. A key question in the survey was: “What are the main value propositions you see for permanent downhole monitoring?” As shown in Fig. 1, the most important value propositions were: 1) optimizing production through continuous information, 2) avoiding the necessity to shut in the well to obtain pressure ratings, and 3) emerging distributed temperature capabilities that add further value in understanding and optimizing production. There was general agreement among both operators and technology providers on the importance of these benefits.
The relevance of these value propositions was stated by Shahab Mohaghegh, president of Intelligent Solutions: “The thought of being able to know what is going on in the well and in the reservoir in real time is very exciting. You imagine sitting in your office thousands of miles away from the field and being able to decide what needs to be done and then being able to see the consequences of your decision in near real time.”
A similar view was expressed by Garrett Skaggs, monitoring product champion at Schlumberger. “The value of permanent downhole monitoring systems stems from the ability to provide continuous, reliable well and reservoir performance information without the need for intervention,” he said. “These measurements enable operators to manage decisions regarding hydrocarbon assets including production optimization, problem identification and diagnosis, updating reservoir models, and field development planning.”
The growing importance of fiber optic technology and distributed temperature sensing was also raised by a number of operators. Significant improvements in these systems over the past few years have led to an increased acceptance of this downhole technology. In the view of Glynn McColpin, director of reservoir monitoring at Pinnacle (a Halliburton service): “I think we are actually seeing the next wave with fiber optic sensing. Electronics can only get you to a certain temperature, then you start worrying about longevity and failures. You start looking at the fiber optic solutions coming out—we can go into steam wells up to 350°C with just glass and the glass itself is a sensor.”
Editor’s note: This is the second installment of a multipart series examining key upstream technology challenges facing the oil and gas industry and the reasons for the lack of accelerated acceptance of technologies needed to exploit increasingly challenging drilling and production environments.
Like managed pressure drilling (MPD) covered in the first installment in this series (see February JPT), seismic while drilling (SWD) is an emerging drilling evaluation technology that many believe provide considerable value to the industry. While not on the market as long as MPD, SWD services are currently offered by several technology providers. As part of this joint analysis of new technology acceptance by Decision Strategies and JPT, an e-mail survey was conducted among approximately 250 SPE members located around the world. The vast majority of these respondents were operators and technology providers, with a good representation of drilling contractors, consultants, and academics also included.
SWD Value Proposition Analysis
Similar to the MPD market analysis, the survey started with the following question: “What are the main value propositions you see for seismic while drilling services?” As shown in Fig. 1, three value propositions were named with equal frequency:
There were no significant differences found between technology providers and operators as to the importance of the three value propositions. As stated by one respondent: “(SWD) will hugely increase the probability of cap rock as we can check the profile periodically and make changes with the help of directional drilling and other relative measures.” These value propositions were further addressed in an interview with Nils Edwards, product manager for Baker Hughes Seismic While Drilling Services. “Over 95% of all wells drilled are based on surface seismic, which has quite large uncertainties, especially in the high-risk subsalt markets,” he said. “By providing check shot and reflective information in real time, the operator can update their surface seismic even while drilling to lessen these uncertainties as the well is approaching the targeted zone. Adjustments can be made to hit the target in the optimal position.”
Other service companies interviewed also explained the significant potential value of SWD. “The emergence of deepwater drilling is adding more complexity in unknown fields,” said Jean-Marie Degrange, acoustic product champion of Schlumberger Drilling & Measurements. “Indeed, deepwater wells are also much more expensive while facing increasingly complex challenges. Our seismic while drilling technology provides bore-hole seismic data while the well is being drilled, which enables accurate time-to-depth conversion of surface seismic data without uncertainty on formation velocity down to the drill bit location. Measurements acquired using this technology offer a unique look-ahead capability without disrupting operations, which provides indications of the structures of reflecting horizons ahead of the bit to support drilling and well construction decisions.”
Editor’s note: This is the first installment of a multipart series examining key upstream technology challenges facing the oil and gas industry and the reasons for the lack of accelerated acceptance of technologies needed to expand the frontiers of exploration and production.
Managed pressure drilling services have been offered for almost a decade and, while some believe it has the potential to be a widely used technology in the future, thus far it has been met with relatively limited acceptance by oil companies. The evaluation of this emerging technology and its acceptance involved a worldwide survey among approximately 600 SPE members who completed an e-mail questionnaire.
In an effort to determine what was important to the participants, the first question asked was: “What are the main value propositions you see for managed pressure drilling services?” As shown in Fig. 1, the most important value proposition cited for MPD is that it allows operators to “walk the line between pore pressure and the fracture gradient.” This capability confirms an important benefit of MPD, and was further substantiated by the second most frequently mentioned value proposition of MPD—that it allows an operator to drill wells not possible otherwise. There were no significant differences in responses to this question between technology providers and users.
The survey results were discussed with both operators and service companies familiar with the technology. Don Hannegan, director of emerging technologies, Controlled Pressure Drilling and Testing Services, with Weatherford International, stated: “In addition to such drilling hazard mitigation applications, a growing amount of today’s MPD applications are for HSE benefits and ‘insurance against a blowout’ on prospects that may be technically drillable with conventional open-to-atmosphere circulating fluid systems. Perhaps one of the more significant impacts of the technology has been that of increasing the amount of reserves deemed recoverable by drilling prospects previously thought to be economically or technically undrillable.” This last benefit would appear to be the ultimate value proposition for MPD.
Lance Cook, vice president of Wells Technology Deployment and Tech Services for Shell, believes that opera-tors and service providers may be looking at the technology differently. “Shell achieves value from the constant bottomhole pressure and the ability to keep the well in balance downhole and, thus, reducing mud cost and avoiding other issues such as stuck pipe,” he says. “Most MPD service suppliers market this constant bottomhole pressure as the primary value from MPD, but they often assume operating companies know more about the subsurface than we actually do. In Shell, we obtain higher value from safely using MPD practices to routinely determine what our pore pressure to leak off gradient is real time with short duration decreases or increases to applied annular back pressure. As most of our MPD operations are on high temperature/high pressure wells, they inherently come with high pressure uncertainty. We also introduce drilling window uncertainty with routine borehole strengthening operations. By eliminating the drilling window uncertainty with MPD ‘finger-printing,’ we are then able to control the constant bottomhole pressure to what is known to be the optimum bottomhole pressure, not relying on pore pressure and fracture gradient predictions.”