An inventive application for Roller Cone (TCI) and Polycrystalline Diamond Compact (PDC) bits (all sizes) that involves reusing the bits in future wells for similar well design types. With factory drilling being carried out in one of the Gas field (among other areas in gas) with over 50 runs a year provides an excellent opportunity to utilize rerun bits, both TCI and PDC, that have a 90-95% life remaining. Using this approach provides an effective and efficient way of cost saving during drilling.
While the cost of new bits in the country is very high compared to markets outside, mainly due to logistics issues with recent and continuous enhancements in bit designs, it makes complete sense to reuse these bits; especially when a huge inventory is available due to so many rigs drilling the similar type well designs in one or similar gas fields. The main criterion is to keep a track of all sizes of bits used on all gas rigs in the area and in the tool house (warehouse). Often, a particular size bit, either TCI or PDC, is used to drill a very short interval in a particular section due to a technical reason for the bit in the well being pulled out of hole, and is almost in brand new condition. Having an up-to-date inventory of these bits from the gas rigs, the tool house, and bit vendors makes it easy to identify such bits and utilize them in new wells, which provides significant cost savings.
Using the rerun bit approach immediately takes the bit cost for that particular hole section to 0$ and so we can achieve additional drilling optimization by utilizing a mud motor in that section, i.e., 12-in., 8-3/8 in., or 5-7/8 in., and further increasing the rate of penetration (ROP) by maintaining the same cost/ft ($/ft) in the section and even breaking bit record runs. In the last few wells it has been evident that by using this approach, the cost/ft for the 12-in. section drilling in the Gas Field field is seen as low as 52% of the new bit for the same year; providing a benchmark for the field. This would not have been possible without utilizing the rerun bits from previous wells. This approach is proving to be very beneficial. As a result of a number of these TCI and PDC bits available in reusable condition as a result of a large number of wells drilled every year in gas fields, significant cost savings have been achieved, which translates into millions of dollars in savings.
The rerun bits have substantial advantages over the new bits, primarily due to cost savings and enhanced bit designs with high durability and bit life over the last decade. For particular application in gas drilling, it is clear that having a large inventory of rerun bits available for almost all hole sizes will enable drilling cost optimization.
For many years, Saudi Aramco has searched for a way to replace the practice of drilling out the DV’s and Shoe Track with a tricone bit, followed by a polycrystalline diamond cutter (PDC) bit to drill the new formation to the next casing point. Many bit manufacturers have conducted trials to overcome the challenge, with limited success. This paper discusses a successful, single-run technology to drill out and continue drilling using only a PDC bit.
Investigations of the root causes of failure and erratic performance led to extensive review of bit design and drilling practices, but fail to overcome the single-run challenge posed by cutter wear and damage experienced during the drill out.
Recently developed shear cap technology provides a means of installing high-grade tungsten carbide caps on the PDC cutters. The caps protect the cutters during the drill out, and then wear away to expose the cutters in pristine condition for drilling the formation.
The shear cap technology has been tested extensively and optimized using various bottom-hole assemblies. The result has been a considerable breakthrough in the success rate for drilling the formation section, accompanied by a time reduction that has resulted in huge savings in offshore oil drilling operations.
The standard PDC bits fitted with the protective technology are successfully providing a one-trip capability, saving a round trip to change the bit and achieving a 100% success rate in drilling to the next the casing point. When drilling in the casing, the tungsten carbide shearing caps are effectively mitigating the cutter damage typically experienced when drilling out the shoe track. Drilling performance in the formation and the ability to efficiently drill the full section, demonstrates the undamaged condition of the cutters when the bit exits the casing. Overcoming the longstanding efficiency challenge of drilling both shoe track and formation in a single run is being achieved with the novel technology’s ability to enable optimal formation drilling by protecting cutters during the shoe drill out.
This paper presents an overview of the technical challenges in the design of floating offshore wind turbines (FOWTs) and the recent development of design guidelines for FOWTs. Extensive case studies, which evaluated the characteristic load conditions and global responses of FOWTs, are carried out to verify the design criteria. Three design concepts, including a Spar-type, a TLP-type, and a Semisubmersible-type floating wind turbine support structure and their associated stationkeeping systems, are selected for the case studies. Representative operational and extreme storm environmental conditions of the East, West and Gulf of Mexico coastal regions on the US Outer Continental Shelf (OCS) are considered. State-of-the-art simulation techniques are employed for the fully coupled aero-hydro-servo-elastic analysis of the integrated FOWT model. Relative importance of various design parameters as well as its impact on the development of design criteria are evaluated through parametric analyses. The paper is concluded with a brief introduction of the recently published ABS Guide for Building and Classing Floating Offshore Wind Turbine Installation.
A significant portion of offshore wind energy resources in the United States are available in water depths greater than 30 meters in the offshore regions near highly populated coastal states. At this and greater water depths, floating offshore wind turbines (FOWTs) could become more economical than bottom-founded designs.
Existing design concepts of floating support structures and stationkeeping systems for FOWTs are mostly developed based on experience from the offshore oil and gas industry, which has witnessed nearly 60 years of designing and operating floating offshore structures. There is a wealth of knowledge about hydrocarbon-related offshore structures installed on the US Outer Continental Shelf (OCS). What makes FOWTs unique, however, is the presence of wind turbines that follow a very different design approach. Strong interactions between the wind turbine, floating support structure and stationkeeping system also pose a great challenge to the design of FOWTs. Economic considerations for typically unmanned FOWTs further require leaner designs, serial production and mass deployment.
For these reasons, it is not technically sound or economically acceptable to transfer existing technologies of hydrocarbon-related offshore structures directly to FOWTs without further calibrations and necessary modifications. To address this, the Bureau of Safety and Environmental Enforcement (BSEE), U.S. Department of the Interior, awarded a research project to ABS in 2011 under its Technology Assessment and Research Program. The project was aimed at conducting a thorough review of existing technologies relevant to FOWT floating support structure and stationkeeping system designs and evaluating global load and response characteristics using the latest simulation methods. A draft design guideline for FOWT floating support structures and stationkeeping systems also was proposed based on the research findings of that project.
This paper presents a summary of the BSEE-funded research (Yu and Chen, 2012) as well as the subsequent development of the ABS Guide for Building and Classing Floating Offshore Wind Turbine Installation (ABS, 2013).
Placement and timing of steam injectors is critical for optimal performance of the Steamflood at Round Mountain Oilfield; a dipping, highly permeable reservoir with a very strong water drive. Diligent reservoir management to conserve steam is a necessity in any steamflood, especially if a strong water drive is present.
In the Round Mountain Field, with primary water cuts of 99.5%, steam injection was instituted at an up structure position (Row 0) in 1998. Water was produced with high volume lift electric submersible pumps (ESPs) in wells two rows down structure (Rows 1 & 2) from the injectors. These down structure wells intercepted encroaching aquifer and reduced reservoir pressure; imperative for steam front expansion. As the steam front advanced, wells that were formerly water intercept wells (Row 1) began to heat up and produce oil at low water cuts. These wells were placed on beam units, and new water intercept wells (Row 3) were drilled one row further down structure.
Heat losses to Overburden, Underburden, and by hot fluid withdrawal over time decreased the rate of steam front expansion. This paper discusses the "Steam Injector Relocation?? strategy devised to specifically tackle the problem. By this strategy, once the down structure row of producers (Rows 2 & 3) experience slower steam front expansion and the up structure wells decline in production, the up structure row (Row 1) is converted to injection. This leads to a more favorable expansion of steam front, significant improvement of production, and lower heat losses. This process has been repeated four times, and at present the steam front is approaching the original oil water contact in some areas of the field.
The lessons learned from this project emphasize the need for careful and continuous surveillance of production, pressure, flow line temperatures, and heat losses in order to move both injectors and producers at critical times.
The Archie's equation lost its role in tight gas sands due to the complicated pore structure and strong heterogeneity. It's a challenge to determine the input parameters in the Archie's equation. In this paper, 36 core samples, which were drilled from tight gas sands in China, are chosen for resistivity and NMR laboratory measurements. Based on the experimental study of these core samples, the influence factors to electrical properties are concluded to reservoir porosity and the proportion of small pore components. When the porosity is higher than 25%, the relationship between the porosity and the formation factor illustrares a power function, this is coherent with the classical Archie's equation. When the porosity is low, the statistic line of the porosity and the formation factor bend to the left. The relationship between the porosity and the formation factor is not a simple power function, the parameter of m is various and relevant to porosity. The relationship between the water saturation and the resistivity index is divergent, the saturation exponent n varies from 1.63 to 3.48. After analyzing the corresponding NMR laboratory measurement for the same core samples, an observation can be found that the saturation exponent is relevant to the proportion of small pore components. When core samples are dominant by the small core components, the corresponding saturation exponent is high, vice versa. To estimate reservoir initial water saturation accurately, the pore structure information must be considered.
Machuca, Laura L. (Corrosion Center for Education, Research and Technology (Corr-CERT), Curtin University) | Bailey, Stuart I. (Corrosion Center for Education, Research and Technology (Corr-CERT), Curtin University) | Gubner, Rolf (Corrosion Center for Education, Research and Technology (Corr-CERT), Curtin University) | Watkin, Elizabeth L.J. (Corrosion Center for Education, Research and Technology (Corr-CERT), Curtin University) | Ginige, Maneesha P. (CSIRO Land and Water, Underwood Avenue) | Kaksonen, Anna H. (CSIRO Land and Water, Underwood Avenue)
ABSTRACT:Appraised Dry Film Thickness (ADFT) is a recent statistical approach regarding DFT interpretation onto any steel structure regardless of its size and complexity. The concept was initially presented at the EUROCORR 2010 Conference in Moscow. ADFT is a useful tool that met interest and has been adopted by co-authors as alternative acceptance criteria to the 80/20 rule and the 90/10 rule (the former explained in ISO(1) 198401 – hereafter called ISO-standard). ADFT was implemented recently (February, 2011) in painting specifications due its advantages over formerly mentioned rules (e.g., easy visualization of the amount of paint applied, durability forecast and so on). As a result of the cooperation, the ADFT concept has been implemented on a wider scale. The concept is based on Gaussian approximation of the DFT measurements'' batch. Two different values can thus be calculated from the mean and standard deviation: ADFT or ADFT90. The former corresponds to the 80/20 rule whilst the later to the 90/10 rule. Both formulas are very simple: ADFT= xm – 0.84·σ and ADFT90 = xm – 1.28·σ, where xm and σ mean the average DFT and standard deviation, respectively. In order to check the acceptance of the painting job, one has to compare the ADFT (or ADFT90) value to the NDFT (Normal Dry Film Thickness).
Anyone who has ever played a role at a construction site or at least witnessed the inspection of coating, has faced the problem of Dry Film Thickness (DFT) assessment. It is easy to check DFT in one point or to determine the thickness of a small sample area, whilst with regard to a complex and large structure. The customer must have and be able to use traceable criteria not only to accept or reject but to classify the stage and quality of work.