In high pressure high temperature (HPHT) reservoirs and exploratory wells, especially in deep water, there is a higher degree of uncertainty, which can increase the operational costs due to non-productive time (NPT) and operational problems due to the unpredictable nature of these wells. For these challenging wells with narrow windows, Managed Pressure Drilling (MPD) techniques offer cost-effective tools to increase the odds for achieving well and cost objectives assurance. There are significant benefits from early implementation of MPD in the project life cycle. These benefits include from improving operational efficiency to risk mitigation and safety enhancement. However, there is an enormous potential that many operators have been missing. This is related to the incorporation of MPD as a driver in optimizing the well design, which could greatly increase the possibilities of reaching target depth, and potentially prepare to eliminate one or more casing strings. Current well design process hinges on the ability to manage uncertainties by company or regulatory requirements, such as kick tolerance and safety factors. This work addresses the value added from implementing MPD in early stages in the project life cycle through the analysis of case studies. The cost savings from the impact on the well design are also discussed. This work also presents a in depth discussion on the benefits, and enablers of this approach. Furthermore, it presents considerations by taking advantage of dynamic processes facilitated with MPD. Finally, new guiding criteria to aim to constitute a systematic and integrated approach to ensure well integrity and optimize well design while also considering the operational implications and integral cost benefits is proposed to the industry. This paper represents the initial phase of a compressive long-term project to integrate two main components of well design. These are MPD adaptive well design, and statistical analysis based on variations of load and/or strength.

MPD techniques have being applied to drill zones with major fluid losses or narrow operational window. Nevertheless, subsequent operations are not yet at the same stage of development: Wireline logging, running casing and cementing are still challenging and need further development when it comes to DP rigs. Therefore, after drilling a well with hydrostatically underbalanced fluid and surface backpressure, it is necessary to replace the drilling fluid in order to continue the operations. Although, in nearly all MPD wells it is possible to do this, the major challenges are zones with absent drilling window and severe losses where PMCD technique is required. In these cases, it is not possible to use overbalanced drilling fluid. This paper presents a solution for wireline logging while using MPD techniques on DP rigs with underbalanced drilling fluid. At first, it shows the planning phase and its discussion, then the execution phase with its difficulties.

The use of the Managed Pressure Drilling (MPD) is spreading in offshore operations. The increasing complexity in the new exploratory frontiers is demanding for new techniques to reduce costs and increase operational safety. MPD appears as an answer for that demand and sometimes it is the only viable way to drill some of the challenging wells. In that way, understanding the gas migration behavior while drilling in PMCD mode allows an optimized well design concerning cost and operational safety. The present study validates a mathematical model capable of simulating a scenario where loss of drilling fluid in the bottom of the well is present while having an influx from the same reservoir and observing gas migration to the surface in a PMCD operation. A Drift Flux Two Phase Flow Model is used in association with the Advection Upstream Splitting Method (AUSMV). Before the presentation and discussion of the complete PMCD scenario, two simple cases were simulated and the results were compared to the ones from a computer application considered as a reference to the industry, validating the proposed model. The results of the simulations can be used as a base for the elaboration of operational procedures to monitor gas behavior and optimize bullhead in PMCD scenarios.

The naturally fractured Buda formation, which underlies the Eagle Ford shale play across central and south Texas, is experiencing resurgence in exploration and production activity as a result of improvements in horizontal and underbalanced drilling techniques. Formed during the Cretaceous period, the Buda formation was produced from vertical wells for decades, leaving aside the potential of crossing all the vertical fractures and associated recoverable hydrocarbons. However, many fractures in the Buda formation are underpressured because not filled with hydrocarbons from the overlying Eagle Ford formation. The application of Underbalanced Drilling in horizontals wells to drill Buda wells is today showing excellent results. The underpressured nature of some fractures in the Buda dictates that wells be drilled underbalanced; drilling the formation conventionally typically results in issues such as considerable circulation losses and then associated kicks when drilling through depleted and filled fractures. In certain areas, the Buda formation also presents the challenge of hydrogen sulfide gas (H 2 S), which poses environmental and safety issues. In some cases, the Buda's fracture systems may be vertically extensive enough to establish hydraulic continuity with underlying formations, a situation that could result in extraneous water production. This paper examines a case study employing Underbalanced Drilling (UBD) techniques to drill a well in the Buda Limestone formation. Before embarking on the project, the operator conducted a six-county assessment of the Buda, comparing wells that were drilled using a conventional mud system with wells that were drilled using underbalanced drilling techniques. A significant concern with drilling the wells conventionally was that the weight of the drilling fluid column would create pressure against the 5.0 pounds per gallon (ppg) or less from sub pressured fractures from Buda formation, which could result in severe to total loss of drilling mud. Even drilling this formation with freshwater applies 8.33 ppg of pressure for a column of fluid. The study revealed the UBD wells mitigated the loss of drilling fluid and allowed the producing section to be drilled successfully to total depth. Using UBD techniques also yielded significant improvements in production through its ability to prevent drilling mud and chemical additives from invading the drilled formation. With the UBD approach, the operator was able to drill the production section of eleven wells (at today) to TD (Target Depth) using an open-hole completion and effectively control low-pressure zones. The approach resulted in benefits such as reducing rig time and nonproductive time (NPT), incurring minimal fluid losses, obtaining early production of crude while drilling, and characterizing the reservoir for future developments. As the industry continually strives to meet the ever-growing demand for hydrocarbons worldwide, new technologies are seeing expanded application not only in emerging, but in mature conventional plays with untapped potential. UBD technology was combined with advanced MWD tools, mechanically operated wellbore isolation devices, multibore wellhead system and efficient four phase separation. This has provided the operators an opportunity to have a second look at the Buda formation and overcome steep challenges to produce wells more efficiently and economically than before.

In the Unconventional Loma Campana Oil Field, located in Neuquen, Argentina, the primary target is the Vaca Muerta shale, and the secondary target is the Quintuco carbonate. Both formations are naturally fractured and present high formation pressures and a narrow mud weight operating window. Those conditions generate operational issues (influx or fluid losses) and are the primary reason for the use of the Under Balanced Drilling (UBD) technology through problematic zones. When using conventional BHA for UBD operations, after reaching TD, it is necessary to kill the well, by increasing mud weight, in order to pull out of hole and run the casing. This heavier mud exerts high ECD during the cement job causing partial or total loses of returns. In other cases, when the formation pressures are too high to be controlled with the mud weight, it is necessary to unload the well until reservoir pressure decreases to the manageable level. This operation has high impact on both time and cost of the well. By the use of the casing drilling technology and with the knowledge of the operating window it is possible to perform managed pressure cementing (MPC). This is done by exerting back pressure needed to adjust the ECD within the operating window detected in the region of interest for each stage of the operation. With this technique there is no need to kill the well. The main goal, to reach the desired height of cement, is achieved by minimizing fluid losses and controlling influxes. This paper contains information that will help develop cementing fluid design, pump schedule, and required back pressure in each stage of cementing job.

The general form of drilling rigs has remained relatively unchanged for decades. Yet equipment, systems, and methods of a modern rig would be unrecognizable to crews of 20 years ago. In structured tasks, manual controls have largely yielded to automated control systems that require minimal crew intervention. Automation has increased the feasibility of many projects through the use of managed pressure drilling techniques which were previously impractical, if not impossible. But this separation of crew from manual controls, especially with the introduction of new MPD methods, has changed the role of the operator and has invited questions regarding competency and how it is achieved. Automation has benefitted the industry, but to properly adjust to these changes, it must be recognized that the role of the driller and crew has changed not only in degree but also in kind. This paper is meant to highlight the growing gap between conventional and future competency requirements by discussing new challenges which exist between the driller and the rig brought on by automation as well as difficulties related to the expanded use of new MPD methods. Similarities exist with pilot awareness in the aviation industry that will be discussed along with potential solutions. However there are a unique set of challenges will be addressed which face the drilling industry presenting greater difficulty. Ultimately, a portrait of a future competency program will be presented.

Underbalanced drilling has been proven to mitigate formation damage, increase rate of penetration (ROP), and reduce differential sticking of the drill string. This paper describes the benefits of using open hole multistage (OHMS) completion systems in unconventional wells that have been drilled underbalanced. While underbalanced drilling and completion is not the standard, it is being utilized significantly in the United States due to reservoir characteristics. This paper discusses four types of underbalanced wells where open hole multistage completion systems have been installed: air drilled and nitrogen fractured, low bottom hole pressures, lost circulation scenarios, and those drilled underbalanced for reservoir benefits. Each scenario offers its own unique advantages specific to the reservoir, but also distinct operational challenges. Detailed discussion of the formation characteristics, and drilling, and installation operations for each of the four case study scenarios of underbalanced wells coupled with OHMS completion systems is provided. Case studies covering examples in shale, sandstone and carbonate plays in the United States are presented. With over a thousand wells completed with OHMS systems in managed pressure situations, this paper will provide a detailed evolution of operational best practices for installation of OHMS systems in these wells. Therefore, the information presented will address operator concerns regarding the risk of completing underbalanced wells with multiple tools on a single casing string.

After evaluating multiple well profiles to determine feasibility of performing Dual Gradient Drilling (DGD), a need became apparent for a simpler screening tool that can quickly demonstrate the utility of a given DGD variation compared to other drilling methods. Subsequently, the ‘Depth Ratio method’, or ‘DRx Method’ and ‘Density Depth Ratio Matrix Method’ or ‘ρDRx Matrix Method’ have been developed. These methods utilize basic physics to evaluate DGD’s utility, and are independent of factors such as geographic location and DGD method. DGD helps in adjusting the pressure exerted by the drilling fluids on the open wellbore and formation by conveniently splitting the annular pressure profile into two separate and manageable gradients at the ‘point of dual gradient (DGp)’. At DGp, there can be modifications to systems’ a) net energy content, b) overall mass, or c) both. Using the ‘DRx method’ and computing a ‘ρDRx matrix’, the utility of a given DGD system performing under its minimum and maximum densities (where mass and energy changes are expressed in equivalent densities), can be evaluated. This gives a range of feasible operation for the DGD system. This information can then be compared to actual pressure profiles that are being tested for DGD, and a very quick screening for possible application of DGD can be performed. DRx and ρDRx matrices can be applied for both ‘Normal Gradient Drilling’ (regular/abnormal pressure profiles) and pressure regression profiles (i.e., "Reverse Gradient Drilling").

Managed Pressure Drilling (MPD) continues to offer a solution to today's growing number of previously "undrillable" technically-challenging wells. With more operating companies looking to incorporate MPD into their well designs and programs, service companies are facing a severe shortage of experienced field personnel capable of meeting this demand. To remain successful, the industry must be able to recruit, train and drive new personnel to competency in a timely fashion, minimize costs, and maximize productivity for the product line. Training challenges faced by a young product line like MPD include the recruitment of competent field personnel on the rigs; the creation of training and competencies programs geared towards specified job roles; the development of informed instructors and mentors; and the implementation of an effective training system. In this paper we will suggest the next steps of having a complete development program that focuses on training through a combination of computer based training (CBT), classroom training, and simulation with a hand's on equipment component. Competency that has specific performance criteria the employees will have to meet before advancing to the next level and a mentoring program through on the job learning. These three foundations will re-enforce concepts, techniques, and applications of MPD and ensure the industry will have a trained and competent work force that will meet the growing demand of this young product line.

In Tarim Oilfield the Ordovician carbonate reservoirs develop lots of cracks and caves. The formation pressure is very low(>6000m, less than65MPa), leading to the narrow mud weight window(MWW) problem. Serious lost circulation and reservoir damaged was encountered when we use the traditional overbalanced drilling method, also the oil and gas reservoirs cannot be discovered timely, therefore whole process underbalanced drilling technique must be employed. The underbalanced drilling technique has been applied in the narrow MWW formations, but there’s no report of the whole process underbalanced drilling technique (including the underbalanced drilling, underbalanced tripping, underbalanced logging and underbalanced completions, etc.) being used in such formations in China. Based on the analysis of difficulties encountered by traditional overbalanced drilling methods such as serious lost circulation, horizontal wells cannot reach the design sections, serious damage to the reservoir, the feasibility analysis and construction plan of the whole process underbalanced drilling in Y block is proposed. The first whole process underbalanced drilling of horizontal wells in Tarim Oilfield was conducted and completed. Finally 6 layers of reservoirs are being discovered (2 layers are not discovered by the prospect well), the cumulative thickness is 16m, which increases the rate of oil and gas discoveries. Compared with the on-site well, the efficiency of drilling is greatly improved, no lost circulation and no complex situation encountered; the ROP increases 74% compared to the adjacent wells in the same layers. It also created the deepest drilling depth record using the inflatable mud in China. The whole process underbalanced drilling program formed in this thesis provide an effective drilling and completion mode for the Y block in Tarim Oilfield, which greatly increased the rate of oil and gas discoveries, and reduce non-productive time, while this method has some reference significance for the low-pressure reservoir development in the other parts of the world.

Transient flow models play an important role in the planning and follow-up of advanced well operations such as managed pressure drilling and underbalanced operations. The most recent trend is a situation whereby flow models and control engineering algorithms are combined in various settings, to control flow parameters. This requires robust flow models and an in-depth understanding of uncertainties in the modeling process. This paper presents a simple and robust transient model that can handle highly dynamic flow systems. The model, AUSMV scheme, has been developed for academic and training purposes. With the model, students can investigate different flow scenarios and pressure control challenges encountered in general well control, managed pressure drilling, underbalanced drilling, and automation. The capability of this model to handle highly changing flow scenarios will be demonstrated with examples taken from managed pressure drilling and underbalanced operations. The effect of numerical dissipation on the model predictions will be briefly discussed.

Automation has the potential to improve efficiency, precision, and safety of pressure and flow control during underbalanced drilling (UBD). In addition, advanced estimation theory can be used to extract more information from existing measurements to increase knowledge of the downhole conditions during operation. An essential part of an advanced (model based) pressure control system is the hydraulic model. Even with high-bandwidth distributed downhole measurements, a calibrated hydraulic model is required to ensure robustness, e.g. to sensor loss, and obtain real time estimates of unmeasured quantities and reservoir characteristics. In UBD operations, in contrast to Managed-Pressure-Drilling (MPD) operations, the flow in the annulus is inherently a multiphase gas liquid flow, which severely complicates the modelling. Much effort has been put into developing multiphase flow models, however, to date; most of these are very complex, requires extensive configuration and are not well suited for real-time applications. Consequently, a major gap with respect to automation of UBD is the lack of a fit-for-purpose model capable of reproducing the main dynamics of the multiphase flow in the annulus, while being sufficiently robust and suitable for real-time applications. In this work, we present recent advances on the development of a simplified fit-for-purpose model of the distributed gas-liquid dynamics, suited for advanced control of UBD operations. Using an automated calibration procedure, the model is shown to retain accuracy in a realistic case study. It is also shown that its reduced complexity enables real time coupling with measurements to obtain estimates of unmeasured quantities such as gas distribution and perform reservoir characterization.

Tight gas reservoirs are often characterized by complex geological and petrophysical systems as well as heterogeneities at all scales. In addition, the operating environment is very challenging and that affects the decisions for data acquisition. The use of salt-saturated or oil based mud systems creates a contrast and uncertainty in the data. Hence, the quality of static log and core data acquired is compromised. In May of 2008 Shell’s Global Wells and Exploration Management made a strategic commitment for the use of Underbalanced Drilling (UBD) for reservoir characterization on all tight gas exploration and appraisal wells. UBD is unique in that, when properly applied, it completely eliminates any uncertainty of drilling or completion fluid damage from the dynamic gas mobility understanding. Specifically the technology has been used in the exploratory and appraisal campaigns to obtain the direct benefits of characterizing the reservoir while drilling, obtaining the real net productive pay zones of the reservoirs and establish whether open fractures were crossed. UBD has also been used to determine reservoir volumes connectivity and obtaining other important reservoir properties in real time, which helps in calibrating the reservoir models. Gas flowing during UBD has been used to optimize the testing, logging and completion plans that were conducted after drilling each of the exploratory wells. Since 2008 Shell has successfully deployed UBD for tight gas exploration and appraisal on 10 projects in North America, North Africa, the Middle East and Asia. This paper will evaluate the strategic learning’s from this deployment of UBD. Evaluation scope will include HSE, project delivery issues, reservoir learning’s and changes to sub-surface team’s work flows to exploit the information. Selected project results will be presented to support the evaluation conclusions. Discussions will include a view to the future including how Shell is changing overall tight gas project development with UBD de-risking.

Well construction is a complex job in which annular pressures must be kept inside the operational window (limited by fracture and pore pressure). Monitoring bottomhole pressure to avoid fluctuations out of operational window limits is an extremely important job, in order to guarantee safe conditions during drilling job. Several operational parameters have a direct impact on bottomhole pressure such as flow rate, rate of penetration, drilling fluid properties, etc. This way, due to the several parameters to be handled, bottomhole pressure control is a complex task and is (nowadays) a manual and very subjective job. Thus, control and automation of drilling operations is a required activity for future challenge of petroleum engineering. This job presents the results of the implementation of a phenomenological model aiming the development of a classic PI (proportional - Integral) controller for bottomhole pressure during a drilling job. Some strategies were investigated by handling flow rate and a choke opening. An experimental unit was built to study pressure control, when the system is disturbed by an ROP steps or choke openings. Results show a non linear behavior, what requires the system investigation in different operational conditions in order to make a classic PI controller reliable. This fundamental study represents an important step in the understanding the requirements for the implementation of the drilling automation process.

This paper reviews an offshore underbalanced drilling project in the Danish sector of the North Sea, undertaken during the summerof 2010. Two oil wells were drilled from a jack-up drilling rig, with produced oil and gas transferred to the accompanying production platform. A closed-loop circulating system was employed, to mitigate against the potential for release of gas vapours, completely bypassing the rig’s pits and shakers. Crude oil was initially selected as the drilling fluid for the reservoir section to reduce the baseline coefficient of friction and minimise the potential for emulsions. A bespoke disc-stack centrifuge was utilised to control the composition of drilling fluid injected into the standpipe by removing fine chalk solids and separating the oil from any produced water. Underbalanced drilling was identified as an enabling technology to combat conventional drilling challenges due to variations in pressure profile along lengthy horizontal sections.

AGOCO is one of Libyan NOC affiliated companies; decide to pioneer the introduction of a new way of drilling horizontal wells in the Sarir C – North field. As one of the conclusions from the rock strength and wellbore stability undertaken on C- North core was that in order to maintain wellbore stability at such low reservoir pressure, any horizontal drilling in member 5-AA must be undertaken using controlled pressure drilling methods that will require an Under-balance drilling Unit. The main objectives was to drill the horizontal reservoir section to TD at 10767 ft eliminating or minimizing lost circulation where no drilling time would be lost due to cure losses, also to reduce the formation damage. The C-349 H well was the first UBD horizontal well drilled by AGOCO. The paper discusses the objectives, planning, and the performance of horizontal UBD well as the first well drilled by AGOCO.

Often times reservoir and drilling engineers are faced with the decision on how best to construct a well to exploit zones of interest while seeking to avoid drilling problems that contribute to reservoir damage or cause loss of hole. The decision to pursue either Underbalanced Drilling (UBD) or Managed Pressure Drilling (MPD) operations is based on the intent of applying the most appropriate technology for the candidate well and entails either an acceptance of influx to the surface or avoidance of influx into the wellbore. Although there are some similarities in equipment utilization, it is a mistake to equate the two technologies as being the same. The merits of each technology will be described to aid in the decision-making process.

The entire range of Managed Pressure Drilling (MPD) applications (Traditional, Advanced, and Expanded) has continued to progress in the last few years, thanks to technological advances in equipment, software, and processes, along with changes in approach to solve complex drilling problems. Even though the term “MPD” was first coined in 2003, several of its variations have been tested and used in the industry for a very long period of time, dating back to as early as the 19th century. Until now, several MPD wells have been drilled for purposes and objectives ranging from ‘fighting narrow pressure windows’ to ‘pore-pressure prediction’, more so in the last decade. However, the big question for any upcoming project always remains: “to MPD or not to MPD”. Even with all the advances in science and technology and increased availability of equipment and expertise, the industry still lacks a Candidate Identification Mechanism (CIM)/Candidate Selection Model (CSM) that is exclusively developed for MPD and its applications, and considers the engineering and economic aspects of the given project. A new MPD CIM described in this paper provides a basic tool that takes into consideration the available engineering data and determines if MPD is a solution for the given project/field/well. This MPD CIM is a result of constant interaction between the petroleum industry and the Petroleum Engineering research program at Texas A&M University (TAMU). The candidate selection model and software, which comprehensively explain the MPD CIM, are supported by an MPD wells database and the TAMU research thesis.

The oil from the Ngimbang Carbonate reservoir in Sepanjang Island, East Java, Indonesia is composed mostly of heavy black oil with a pour point of 120°F and a wax content of 24.89%. Its specific and API gravity are 0.8574 and 33, respectively, and the bottomhole temperature is 223 °F. Underbalanced drilling (UBD) operations in this high-pour-point oil marginal reservoir, for two wells, SED-3 and SED-4, were planned to achieve the main goals of improving reservoir productivity, avoiding reservoir damage, enabling fracture identification, and making testing while drilling possible. Secondary benefits expected by employing underbalanced drilling techniques included avoiding drilling fluid losses, increasing the rate of penetration, and minimizing drilling problems. This paper presents the details as to how the challenges of drilling in UBD mode in a reservoir with high-pour-point and waxy oil were addressed in the planning stage and how the UBD program was implemented in the field. The circulating system for the UBD operation was designed with the capability to heat the fluid system to above the pour point to avoid solidification of the fluid. The drilling fluid was to be heated to 160°F and kept at this temperature to prevent damage to the drilling elastomers. Agitators were installed on all the tanks to prevent wax formation. The effectiveness of these measures and the lessons learned from the UBD operations on these two wells are presented. The paper provides an overview of the achieved well objectives and show that UBD in a heavy oil marginal reservoir is beneficial.

Abstract One of the perceived blockers for Underbalanced Drilling (UBD) operations globally is the necessity for flaring gas in most operations. As the world becomes more aware of the impact of CO 2 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 make often argue that due to flaring requirements, UBD is not aligned with corporate directives and is is not environmentally acceptable. Thus the technology is eliminated as a considered option when finalizing field development plans. As the UBD industry has matured, use of UBD to increase production and reserve recovery from wells, which has resulted in a reduction of the number of wells needed to develop a field. 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 paper will evaluate the trade off of increased CO 2 emissions from UBD flaring against reduced CO 2 emissions from fewer required wells, reduced steel requirements and reduced rig time. Case studies of several Shell UBD projects will be presented to determine the "CO 2 cost neutral point" and if the projects reduced or increased global CO 2 emissions. Conditions under which UBD may be justified to reduce project CO 2 emissions will be determined and discussed. Introduction With acceptance that global CO 2 is resulting in climate change governments and industry are adapting their expectations and behavior. In this environment it is easy to focus on "visible" CO 2 emissions, which flaring from any source certainly is. If however we are going to make real reductions in CO 2 emissions we must calculate the numbers and base our actions on technical/engineering study. In short, the following questions must be asked and answered: Do I want to do something because I think it will make my company or myself "look good"? Do I want to do something because it will make me "feel good"? Do I want to do something because I think it will reduce the CO 2 emissions? Obviously the optimum answer is "all of the above", but as with any complex issue detailed analysis can often lead to hard choices; UBD flaring is one of those cases. A position that flaring is necessary is paramount to "looking bad" in our cultures and can be a lightning rod for criticism from our peers and management, but what if it actually reduces overall CO 2 emissions? A big part of the problem is people tend to accept what they feel comfortable with and focus on what they are uncomfortable with, independent of the facts. Calibration of this emotional response can be made with a comparison of global flaring from the oil and gas industry to the aviation industry. The oil and gas industry is estimated to have flared 1.2 TCF of gas in 2005, about halve of its worst annual flaring in the 1970s. This still constitutes a huge amount of CO2 emissions, with Russia and Nigeria competing for "worst place". This is enough "wasted gas" to supply the global natural gas consumption for approximately 13 days and unquestionably needs to be reduced. However as a comparison, the CO 2 emissions for oil and gas industry flaring at 187 million tone annually is comparable to the airline industry emissions of 183 million tone annually. Yet emotionally seeing a picture of a flare in the jungles of Nigeria makes us feels bad and a picture of a smiling family flying on a vacation. The point being, that doing things that we know will reduce CO 2 emissions from hard numbers will need to take priority over what makes us look good or feel good if we are to maximize CO 2 emission reductions. Global emissions by source category should be considered when discussing how to make meaningful reductions to CO 2 emissions. Simply put, we need to focus on the categories that have high CO 2 emissions.