In mid-2000 BP invited a group of suppliers and drilling contractors to become involved in a deepwater development project in the Gulf of Mexico named "Mad Dog". This project involved building and maintaining unique relationships among the drilling contractors/suppliers, BP and its partners on the Mad Dog field. BP employed a process not used before in the deepwater Gulf known as "Lean Drilling™"1 to foster these critical relationships necessary to the early success of the project. This paper will detail how BP selected the drilling and completion suppliers during the conceptual stage of the project and how these suppliers were organized and empowered for success. The paper will examine the Lean Drilling process from the supplier's vantage and comment on the effectiveness of this process in terms of technology transfer and other criteria. Going Against the Grain In the first quarter of 2001 many U. S. suppliers received a letter from BP stating that a new purchasing initiative would soon be used for what BP viewed as commodity services and products. The new initiative would employ a computer-based "reverse auction" process whereby suppliers would bid against each other in an interactive environment for product and service contracts by region. Each supplier could view the responses in real time by its competitors and would be able to submit a new lower bid until a countdown to deadline was reached. This use of "game theory" was touted as the new direction in oilfield procurement. Though oilfield service companies had always endured a traditional arm's length transaction process with operators, the introduction of this reverse bidding process represented a new low in relationships with operating companies. Shortly after the first auction, when another letter from BP arrived inviting suppliers to a planning meeting for the Mad Dog project, an air of skepticism was understandably the prevailing mood at the outset of the session. Sitting side by side with competitors at the initial meeting also did little to brighten the spirits of the assembly of service contractors. In fact it looked and smelled like an attempt to drive prices down by yet another initiative to invoke cutthroat competitive practices. What actually occurred was a surprise to the audience of suppliers. BP project managers for Mad Dog began the session by presenting measurements that clearly showed BP was not among the better performers when it came to deepwater drilling in the Gulf of Mexico. They went on to state that senior management within BP challenged its drilling and completions groups to achieve first quartile performance or projects would not receive sanction to go forward. The BP presenters continued by stating that Mad Dog was only one of several BP deepwater projects that were going forward at the same time. This would tax BP's drilling and completion experienced manpower. Further it meant that there would be a highly competitive internal environment within BP to attract the best service company personnel to become team members on only one of multiple projects. And there were other issues to sort through.

North American unconventional well completion design has evolved dramatically since 2013 in an effort to keep pace with the productivity gains realized in horizontal drilling. Several trends have emerged during the current industry downturn. Among these trends are a focus on core acreage with higher yield potential, the use of longer laterals, a movement towards higher proppant loading (pounds per linear foot), an increased reliance on plug and perf techniques, and decreased stage length and perforation cluster spacing (increased perf density). As a result associated improvements in well initial production (IP) rates and estimated ultimate recoveries (EUR's) have been highlighted in oil & gas operator's quarterly shareholder's reports during 2015 and early 2016. Unconventional multi-stage completion designs have also quickly evolved along a path paralleling these trends. Horizontal well IP rates and EUR's have also been enhanced through the adoption of integrated completion designs. Recently introduced geo-engineered completions rely on cross-functional expertise and software to integrate petrophysical, geomechanical, drilling, and production data into a completion design. In cases where geo-engineered designs were used, wells showed improvements in EUR's over those associated with increased lateral lengths, proppant loading and stage counts. In one recent case using a geo-engineered design it was demonstrated that fewer stages and clusters achieved higher production than offset wells while injecting less proppant and fluid; thus achieving lower completion cost. The use of engineered workflows in tight or unconventional reservoirs is not new. Multiple case histories have been published in recent literature illustrating the use of stress variability/contrast or mechanical specific energy (MSE) to generate brittleness or other fraccability indices to group stages with similar rock characteristics. In contrast to engineered designs, newer geo-engineered designs integrate multiple inputs (attributes) to determine basin and formation-specific weighted algorithms that correlate to stage and cluster production contribution improvement. The geo-engineered approach has proven repeatable and can be accomplished even when key wireline or LWD data is not available. This paper will document how geo-engineered completion designs evolved from engineered workflows. Multiple inputs (e.g. production, wireline/LWD/mud logs, core analyses, and big data from national and state data bases) can be combined to determine stage length and perforation cluster positioning. Case studies will demonstrate that geo-engineered horizontal completion designs deliver superior well production results when compared to geometric, high-intensity plug & perf designs.

Idling during hydraulic fracturing generates considerable emissions of NOX, CO, and particulate matter (PM). Field studies conducted during 2021-22 documented an average of 5 - 10 hours per day of diesel-powered idling during fracturing operations across multiple U.S. unconventional basins. Prior to 2021 boardroom level corporate environment, social, and governance (ESG) initiatives by oil & gas producers focused on limiting gas leaks, Scope 1 (direct corporate) emissions, and overall carbon footprints. Controlling emissions during the idling of hydraulic fracturing equipment, until recently, had not been a high priority on executive ESG lists. "The name of the game in unconventional shale development has quickly shifted from production at all costs to maximizing cash flow and reducing emissions to improve ESG performance. Operators have placed a priority on their ESG efforts as financial institutions have prioritized responsible investing." (Walzel, B. et.al., 2021). By late 2021 concerns associated with idling during fracturing operations drew more attention from operators. The issues of idle waste control (unnecessary emissions, fuel, and excessive maintenance cost), identified as easy to resolve, garnered limited attention. Yet by early 2022, the challenges associated with frac diesel idling remained prevalent and became more acute with the dramatic rise in diesel costs. In early 2022 ESG surveys began to include mention of frac idle waste. Contributing to this is the fact U.S. frac fleets continued utilizing diesel and/or dual fuel (diesel combined with natural gas) engines for 91% of fracturing operations. One of the lesser-known characteristics of Tier 2 and Tier 4 diesel frac pump engines is the fact they burn 100% diesel during idling – including dual fuel engines. Stop/Start technology, first adopted in the auto industry and later by long haul diesel-powered trucking companies, began gaining traction within the oil & gas industry in 2017. The reduction in idle times attributed to Start/Stop systems proved lower fuel consumption and emissions generation rates were possible. This study focuses on the contributions made by diesel Start/Stop technologies. Positive results from 2019 forward substantiate the efficacy of idle reduction methods used in conjunction with hydraulic fracturing. Limiting frac idle times proved effective in reducing frac emissions, lowering fuel consumption, as well as cutting maintenance costs for hydraulic fracturing fleets. This report highlights a new Start/Stop technology with field results from 2021 – 2022. This recent technology delivered a simpler, innovative hydraulic start centralized plug & play method of powering an entire frac fleet rather than using multiple Start/Stop systems installed to electrically start each individual frac pump. The results of a 2022 Permian basin technology field application are presented here.

In 2006 Falcon Gas Storage Company concluded a study of the Dauphin sands in the shallow waters of Mississippi Sound, Alabama. The study was conducted to determine if the depleted reservoir could be used as a gas storage facility. With preliminary seismic analysis indicating a suitable closed structure existed, further studies were done to determine the practicality of drilling and completing a series of shallow gas injection/producing wells. This paper addresses that feasibility and the subsequent well planning challenge which ensued. Introduction The MoBay Gas field has been producing gas since the early 1990's. The reservoir was determined to be unsuitable for further hydrocarbon exploitation and was shut-in on February 14th, 2008. Plans were then put in motion to P&A all of the existing production wells. The field lies in an environmentally sensitive tidal area in water depths from 8 to 15 feet located within sight of nearby Dauphin Island and the Alabama mainland. Further, the project requires drilling and completion operations with a purpose built jackup rig within a few hundred meters of a major commercial shipping waterway in an area of nearly annual hurricane activity. Falcon Gas Storage was motivated to purchase and assess the field as a storage facility because of its proximity to nearby major pipelines and the potential to provide key hub service to the Florida gas markets - a high population state in the U.S. The targeted storage reservoirs are in the Dauphin Sands. These sands are highly unconsolidated with porosities above 30% and permeabilities as high as 4500 mD. A major service company was contracted to perform the mechanical earth model and wellbore stability analysis. This task was completed in 2006 and allowed further planning to take place. Drilling and completion plans followed the wellbore stability analysis. Weatherford was contracted to design twenty-one near horizontal [86°] wellbores for ultimate injection and drawdown usage. An additional six vertical wells were planned as observation and monitoring sites. This paper will examine more fully the near horizontal injection/withdrawal well design. Early in the planning process a decision had to be made on the completion design for the injection/withdrawal conduit in the near horizontal section. This decision would impact the resulting drilling plan. Three open hole completion systems were considered - a gravel pack assembly, a pre-packed conventional sand screen and an expandable sand screen. Subsequent nodal analysis testing in July 2006 resulted in the decision to focus on the use of expandable sand screens to provide reliable sand control and allow the operator to cycle gas injection and withdrawal at higher rates than conventional sand control techniques. The potential use of open hole expandable sand screens significantly impacted the drilling plans due to the requirement to limit washout severity. The screen assembly will be described in more detail later.

Completions and multizone fracturing operations in the Eagle Ford Shale are complex undertakings. Effectively managing hydraulic fracturing projects becomes even more complex when multiple service providers and suppliers are required to work in a coordinated sequential fashion. By late 2009 daylight completions work in the Eagle Ford evolved into 24 hour a day operations to maximize asset availability – primarily hydraulic horsepower. Completions were accomplished in fewer days using the 24 hour approach, but efficiencies and safety suffered. However, a select group of Eagle Ford operators were concerned with the drop in performance. These operators chose to adopt an integrated services approach where one service company provided the majority of equipment and personnel on completions jobs. This new approach achieved both fewer days per completion and high KPI efficiency (e.g. stages per day, fewer safety incidents, etc.) as well as improving communication and teamwork. An explanation of this new approach is detailed here.