Anadarko Petroleum's Marco Polo development is located in approximately 4,300 ft. of water in Green Canyon Block 608, in the central Gulf of Mexico (GOM). The discovery and appraisal wells were drilled in 2000, and the field will ultimately be produced using a tension leg platform (TLP). The development drilling, which will be complete by 1st Quarter 2003, uses several innovative approaches to maximize project value. Some of the approaches challenge current industry trends and will be highlighted in this paper. Introduction Over the past decade, multiple fields in deepwater GOM have been developed and the region remains one of the frontier exploration areas of the world. The challenge of the Marco Polo development is the same as with most projects - to deliver maximum value. What makes this project unique is the approach. The first step was to evaluate the major components to determine the most appropriate use of current technology. Those selected technologies that significantly challenge current industry trends include: Rig Selection. The rig selected to drill the development wells is an Express-Class, dynamically positioned fifth generation semi-submersible with enhanced pipe handling capabilities. Drilling Fluid System. A newly developed water-based mud (WBM) was used in lieu of the synthetic-based drilling fluids (SBMs) traditionally used in the GOM. Cement Design. To address shallow water flow concerns, a non-foamed slurry was used on the conductor casings instead of foamed cement-the predominate slurry for cementing conductor casing in shallow water flow areas in the GOM. Additionally, a flexible slurry was used on the production casing to mitigate annular pressure buildup (APB). Both of these slurries are new developments in technology. Casing and Wellhead Design. The casing design was optimized from the exploration wells and drew on recently published casing failures in deepwater GOM1. Subsea wellheads were used and will be tied back to the surface once the TLP is installed. To meet the design criteria, the wellheads included a "thick wall extension" below the 18 3/4-in. high-pressure wellhead housing (HPWHH). The 36-in. low-pressure wellhead housing (LPWHH) and casing above the mudline was also externally insulated for flow assurance reasons. Rig Selection As with all drilling projects, rig selection plays an important role in success - particularly with batch set operations. Key issues related to rig selection for the Marco Polo project included:The ability to work in high current environments. Immediately prior to beginning the drilling program, a fourth generation, moored semi-submersible had drilled a well in an offset block where loop currents were present. As a result of these high loop currents, the drilling operation was suspended a total of 21 days.Enhanced pipe handling, which could add significant value during batch set operations.Variable deck loadLiquid mud storageBulk storage (cement and mud)Hydraulics Once qualifications were set, the rig list was narrowed down to two rigs;a fourth generation moored semi-submersible that had been used to drill the discovery and delineation wells and an immediate offset; anda fifth generation dynamically positioned (DP) semi-submersible with enhanced pipe handling capabilities. Because a batch set operation was planned, the fifth generation rig's increased variable deck load, additional bulk storage, and enhanced pipe handling capabilities delivered improved performance over the fourth generation rig. These features, combined with DP capabilities, established the fifth generation rig as the optimal choice.
The Piceance Basin, located in Western Colorado, is a 6,000-square-mile basin consisting of vertically stacked sand-shale sequences. Gas-in-place estimates exceed 200 trillion cubic feet. The operator started developing its acreage in 1982 with 160-acre bottom-hole spacing. Over time, dictated by reservoir performance and enabled by drilling and completion technology, such as PDC bits and directional drilling, field development migrated to 10-acre bottom-hole spacing with surface locations consisting of three to four wells per pad. Historically, pricing pressures dictated the use of conventional mechanical drilling rigs. In recent years, as product prices increased and as well inventory in easily accessible areas became drilled up, the need to drill many wells from a single remote surface location became apparent. These purpose-built rigs facilitate this, plus bring multiple performance improvements, environmental benefits, and well cost reduction to the asset. This paper will be presented by E.S. Kolstad at the 2007 SPE/IADC Drilling Conference held in Amsterdam, The Netherlands, 20–22 February 2007. Introduction Rising natural-gas prices and Wall Street demands have come together to create a new culture of aggressiveness in natural-gas development for one operator in the Piceance Basin. As a result, the operator's drilling activity and production have grown significantly in recent years. Meeting and exceeding growing production targets has had significant challenges. Purpose-built efficiency rigs were designed by the rig contractor and the operator specifically to meet some of those challenges. For many years, local natural-gas prices in the region were suppressed. That revenue disadvantage meant that operators did not have access to many of the newest and best technologies, including the latest rig technologies. Performance indicators flattened in response to the lag in technology. The recent boom in natural-gas prices has affected the local market, making it possible for operators to take bigger technological strides and risks. The specific development program described in this paper is a mature field-development project challenged by difficult topography and other land-use complications. With the nature of the program in mind, the operator was faced with the challenge of significantly accelerating the development of assets with greater capital efficiency, safety, and environmental stewardship. A dramatic change in rig design was the only answer. The rig contractor wanted to establish a new operating area within the region and get more of its new-build technology to the market. It was the perfect opportunity for collaboration. Ready to take a technological stride, the operator signed a contract for multiple purpose-built efficiency rigs. Although many of the individual features of the new rigs had already been used in different parts of the world, the particular combination designed into the purpose-built efficiency rigs was a revolutionary application. In about one year from initial discussion to first spud, thousands of possible features were discussed, combined, separated, invented, added, or rejected. Additional features have been added and removed with knowledge gained since the first spud. Signing the contract involved considerable risk. The operator ordered ten rigs of a new design, signed three-year-term contracts that were elevated over other day rates available at the time, and designed budgets and performance goals based on expected but unknown capabilities. Those risks were undertaken with the understanding that purpose-built rigs have higher value in their particular application than any other rigs available. Commitment to the ideal of purpose-built rigs was strengthened by a confidence in the possibility of continued successful design collaboration between the operator's drilling team and the rig contractor. The decisive move in the face of a number of risks has led the operator to a competitive advantage with compounding effects.
This paper presents a case study for improving drilling performance by maximizing penetration rate while ensuring that hole conditions are not compromised. The overall aim was to identify and prevent invisible lost time (ILT) and nonproductive time (NPT) by means of pre-drill engineering studies and real-time drilling optimization. This process was conducted to deliver continuous improvement in a three-well drilling campaign in the East Texas Basin. Prior to drilling the series of three wells in the East Texas Basin, a pre-drill study of information from offset wells was used to calibrate engineering models and identify opportunities for improvement. These were primarily identified by the analysis of mechanical specific energy (MSE) and rate of penetration (ROP) to create a driller's road map (DRM) to optimize parameters that can be controlled on the rig floor (rpm, WOB, flow rate). Calibrated torque and drag (T&D) and hydraulics models were developed to compare and monitor model versus actual (MvA) in real time. During the actual drilling of the wells, potential areas of improvement were determined by analyzing MSE and evaluating ILT/NPT. Real-time MSE analysis was conducted during drilling operations to adjust parameters to increase ROP performance. ILT and NPT were reduced by focusing on connection times, optimizing hole cleaning to reduce trip times, increasing flow rate, and improving bit hydraulics. These analyses were used to generate a focused optimization plan to monitor hole conditions at high drilling rates. This plan was incorporated into a recommended real-time process for the wellsite team. This case history is presented for a three-well development pad in the East Texas Basin. The first well of the campaign was drilled one day faster than the previous well had been drilled, and each subsequent well was delivered in a shorter time with an overall improvement of 30.9%. The Driller's Road Map was refined after each well as part of the continuous improvement process. As a result of improved hole cleaning, major sources of ILT were reduced by 47%. The improved hole cleaning was verified by real-time MvA correlation. The methodology described is being used successfully on other multi-well projects in unconventional reservoirs and other drilling market segments.
The application of modified reaming technology in Mississippi Canyon, deep-water Gulf of Mexico (GOM) has had a beneficial impact on drilling costs. The ability to drill cement and associated downhole float equipment with steerable ream while drilling (DOSRWD) tools has become increasing important in deep-water GOM drilling. The extra trip required by conventional bi-center and eccentric tools adds costly "flat" time to a well's drilling program. Additional improvements in the eccentric bit's geometry and cutting structures has reduced the number of trips and significantly lowered drilling costs. Traditionally, when a ream while drilling system was used, the operator drilled the cement and float equipment with a pass through size bit, then tripped out of the hole to pick up the ream while drilling bottom hole assembly. For example, float equipment and cement in 9–5/8" 53.5# casing was drilled out with an 8–1/2" bit. A trip was then made to pick up a standard 9–7/8" SRWD bottom hole assembly. The DOSRWD's ability to drill cement and float equipment inside casing and then continue drilling ahead, plus the option to use either a tricone or PDC pilot bit depending on directional requirements and formation type make it the appropriate tool for the application. Water-based fluids are preferred in the upper hole section while synthetic mud is used deep in the wellbore. Because of balling concerns in WBM and stringent directional requirements, the operator utilizes metal bearing seal steel tooth pilot bits in most cases (IADC 117). The authors will document rig cost savings ranging from US$40,000 to $105,000 per trip in some applications with total savings exceeding US$388,000 in some instances. Introduction Mississippi Canyon (MC) Blocks 667, 711, and 755 are located 150 miles south of New Orleans, Louisiana in approximately 3000 ft of water. These blocks are considered deep water Gulf of Mexico and pose numerous drilling challenges to the operator.The well plan calls for a relatively large wellbore to be drilled through the reservoir sand to accommodate high flow-rate completions. To successfully penetrate overburden with high pore pressure, the operator has used several hole-opening systems in the area to drill an oversized hole in order to accommodate multiple casing strings in the upper well sections (Figure 1). If not for the narrow margin between pore pressure and fracture gradient in the area, the operator could have achieved borehole diameter requirements through the reservoir sand with a conventional casing design. To date, a total of six wells have been drilled in the aforementioned blocks. All but one of the wells has been directional in nature. Directional well profiles have been either build-hold or build-hold and drop (S shaped wells). The angle build portion of the wells usually takes place in the upper well sections (4000-ft to 5000 ft TVD). Two hole opening systems have been utilized to drill these upper hole sections:The borehole is drilled conventionally and then opened with an underreamer (i.e. drill a 14.75" hole to casing depth then open the hole with a 17" underreamer to set 13.375" casing.The hole is drilled with a 17" steerable ream while drilling system (SRWD). In MC Blocks 667, 711, and 755, formation above the producing horizon consist of gumbo, unconsolidated sand and sticky shales. The unconfined compressive strength of the gumbo and shales is usually below 1500 psi in the upper sections. Although the formation becomes harder at depth, the unconfined compressive strengths of both the shales and sands rarely exceeds 3500 psi (Figures 2 & 3).
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