Rig Availability Research Articles

Maintenance Impact on Geothermal Drilling Operations. A Case Study Approach

This paper develops a simulation-based model to derive critical maintenance parameters towards optimizing a deep drilling rig availability and maintenance costs. Full factorial analysis is performed to derive the effects and interactions of the derived parameters, based on which ones with a significant effect on the availability and maintenance cost are selected. The case study based model incorporates maintenance, spares and workforce strategies for a geothermal drilling rig. The results offer essential maintenance decision support to both the management and maintenance team of the company and have the potential of further offering insights that eventually reduce the cost of drilling.

A Model for Evaluating the Commerciality of an Unconventional Factory Development Outside of North America

Summary The North American shale oil and gas “revolution” relies on four pillars not guaranteed elsewhere: knowledge of the subsurface, a strong oil- and gas-services industry in an open and competitive market, favorable mining rights, and a long oil and gas culture backed by political support. These pillars enabled massive “factory development” on the basis of drilling and fracturing a large number of inexpensive wells. To evaluate the commerciality of a play outside North America and identify its most influential factors, a fit-for-purpose model was developed. It simulates the development of a core area and takes into account technical and economic parameters. An algorithm calculates the drilling and completion (i.e., fracturing) schedule required to reach and maintain a constrained production plateau determined by the capacity of the export pipe. The initial number of drilling rigs and the time required to mobilize them are important factors differentiating the US from other parts of the world where rig availability can be less evident. Wells are drilled in pads, and production is treated at the pad level by use of average decline curves. The model also includes drilling and completion learning curves. Pretax net present value (NPV) and internal rate of return (IRR) are calculated on the basis of oil and gas prices, development capital expenditures (Capex), which are a fine breakdown between drilling, completion, and tie-in costs, and operating expenditures (Opex), which are fixed and variable. The appraisal phase and central-processing facilities (CPF) are also included. Curves of IRR vs. integrated well cost are computed for several values of well estimated ultimate recovery (EUR) and indicate for a given oil or gas price the maximum well cost compatible with a desired level of profitability. A number of interesting conclusions can be drawn from the model. One is the resilience of the production of a field against investment slowdown. A large portfolio of wells does not behave like a single well. Instead, it acts as a “shock absorber” limiting global decline even with reduced drilling and fracturing activities. Another source of resilience is the fact that once the Capex are paid, the Opex are comparatively small, allowing for lower break-even costs. The model also highlights the key role of all consumable costs (casings, mud and cement, completion costs, fracturing fluids, and proppant), which suggests a simplification of the well design, a standardization of equipment, and the negotiation of large supply contracts to obtain wholesale prices. By contrast, drilling time appears as a secondary parameter, a consequence of the relatively low daily rates of the rigs used to develop unconventional plays. Finally, a comparison is made between the development of a derisked sweet area with an expensive appraisal phase and the development of the entire area. Economically speaking, focusing development on a sweet area appears as a high-risk/high-reward approach very similar to a conventional strategy.

Treatment seeking behavior of the dog bite patients in Himachal Pradesh, India: a qualitative study

Background: Rabies is a practically 100% fatal zoonotic disease. A person is bitten every 2 seconds, and someone dies from rabies every 30 minutes. In this regard perception of victim and their attitude towards treatment forms an important role for prevention against rabies. It is noted that in Himachal Pradesh the less knowledge of people about rabies, impact of traditional healers and unavailability of the RIGs and ARVs especially in the primary health centers affect the treatment seeking behavior of the patients. Methods: A qualitative study was done in the three districts of Himachal with effect from 1 st June 2014 to 30 th May 2015. Thematic and simple proportional analysis of the data was done for the interpretation of the results. Results: Males were more victims as compared to females. Most affected age group was 0-15 years. 56.93% of the patients immediately washed the wound, 43.38% of the patients opted the rational treatment where as 57.62% used both traditional as well as rational treatment. Delay and drop out was seen in 69.24% and 21.53% of the patients respectively. Conclusions: Treatment seeking behaviour of the patients affected by the number of factors. Awareness among people about rabies and ensuring the availability of RIGs and ARV at all the levels of health care centers is necessary.

Riglessly Restoring the Functionality of Subsurface Safety Valves

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164370, ’Innovative Methodology To Riglessly Restore the Functionality of Subsurface Safety Valves (SC-SSSVs) With Damaged Control Lines,’ by Mohamed Fahim, Hossam Elnaggar, Abd Allah ElBarbary, Mohammed Abu Arab, Ashraf Keshka, Hamdi Bouali Daghmouni, and Mohamed Al Karra, ADCO, and Ammar Soufan, Joseph O'Connor, and Magdi Elasmar, Baker Hughes, prepared for the 2013 SPE Middle East Oil and Gas Show and Exhibition, Manama, Bahrain, 10-13 March. The paper has not been peer reviewed. The surface-controlled subsurface safety valve (SC-SSSV) is an integral part of the overall safety system of any well, and it is the only method that provides subsurface isolation in case of emergency caused by uncontrolled surface or subsurface events. The effectiveness of these valves can be threatened by leaks, plugs, or breaks in the control lines (CLs). This paper describes a methodology that deploys CLs on the inside of the tubing, reducing cost and ensuring continued effectiveness of SC-SSSVs. Introduction Functional SC-SSSVs must be installed in production tubing in all gas and oil wells, irrespective of location, as a safety barrier to halt flow in case of a catastrophic failure. SC-SSSVs are held in the open position by introducing hydraulic positive pressure from the surface. This pressure is applied through a CL in the tubing/ casing annulus running from the valve to the surface. In case of an emergency shutdown, the hydraulic pressure will be lost, forcing the safety valve to close. CLs for SC-SSSVs could leak, plug up, or break, leading to loss of the capability to control the valves’ operating condition, causing environmental and safety concerns in addition to a loss of production upon closure of the valve. In one of the giant Abu Dhabi onshore oil fields, approximately 160 strings have with damaged-CL problems. In the past, the only way to rectify SCSSSV problems was to pull out the production tubing through a rig workover. Hence, all affected wells were enrolled in a drilling workover schedule. Rig availability is one of the major challenges affecting field-development plans, and so any rigless technologies that can be used in place of rig workovers are of high importance to save on rig time. A multidisciplinary team was formed to survey the market and carry out an evaluation of technologies that could remedy the problem of the damaged CL by replacing or modifying the existing SC-SSSV riglessly. The findings of this survey indicated that there were two technologies that could restore the functionality of the SC-SSSV riglessly. One of these is an SC-SSSV with a CL line deployed inside the tubing (Fig. 1). This can be compared with conventional CLs, which are set in the annulus (outside the tubing string) and hence require rig intervention in case of damage. The running and retrieval of this modified SCSSSV are performed by a conventional slickline unit; however, the CL requires special equipment (a capillary unit) for installation and retrieval.

A branch-price-and-cut algorithm for the workover rig routing problem

In an onshore oil field, the productivity of oil wells decreases when they require maintenance. To restore full productivity at a well, it must be visited by a specially equipped vehicle, called a workover rig. Given a set of wells needing maintenance and a heterogeneous fleet of workover rigs, the workover rig routing problem (WRRP) consists of finding rig routes that minimize the total production loss of the wells over a finite horizon. The wells have different loss rates, require various services, and may not be serviced within the horizon due to rig availability. The rigs have initial positions and do not have the same equipment. This paper presents the first exact algorithm for the WRRP, namely, a branch-price-and-cut algorithm that relies on some of the most recent techniques introduced for the vehicle routing problem with time windows. Our computational experiments show that this exact algorithm can solve practical-sized instances in reasonable computational times.

World's Deepest Through-Tubing Electrical Submersible Pumps

Summary This paper describes the development, history, and successful deployment of the world's two deepest through-tubing-conveyed electrical submersible pumps (TTCESPs). These are the first TTCESPs deployed inside of 7-in. casing. Electrical submersible pumps (ESPs) are a form of artificial lift that consists of a pump, motor, and electric cable, typically deployed by a rig and connected to electric power at surface. Their advantage is that they create greater drawdown than other forms of artificial lift, thus achieving higher production rates. However, conventional ESPs require expensive workover rigs to replace pumps, the component that fails most frequently. ConocoPhillips Alaska developed TTCESP technology to replace failed pumps rapidly and economically. In this system, a rig conventionally deploys the electric cable, motor, and seal sections with a special latching device for the pump. The pump is pulled and replaced with slickline (wireline) or coiled tubing, eliminating the requirement of a rig. The original through-tubing-conveyed (TTC) systems were developed for 7⅝-in.-cased wells. During approximately the past 10 years, it was common belief that they could not be deployed at the Milne Point field in Alaska because of the limitations of its smaller wells (7-in., 26-lbm/ft casing). This paper discusses the enabling technologies that were developed to allow running TTCESPs in 7-in. casing, including a wellhead spoolpiece and low-clearance ESP clamps. West Sak TTCESP run-time data indicate that the time between rig workovers (RWOs) will increase from 3.5 to 6 years. Pumps can be replaced for 5–10% of rig costs without the safety and environmental impacts associated with rigs. Additionally, production impacts while waiting for a rig are eliminated because slickline and coiled-tubing units are readily available on the North Slope of Alaska. TTC pumps can easily be upsized or downsized to optimize pump flow rate because of changes in production rates. This technology is of interest in areas where rig costs are high, including Arctic, remote, and offshore locations. It is also beneficial where rig availability is low.

Platelet-Technology Applications Provide Economic Remedy for Well-Integrity Problems

Technology Update Up to 40% of the world’s oil wells are shut in, or operating with dispensation, because of well-integrity problems. With the proportion that large, these wells collectively represent major potential for increasing production to meet oil demand—growing globally each year by 1 million BOPD—if improved and more-economic remedies for these problems can be found. Better remedies can reduce the need to drill new wells. With the right technology, leaks in casing, tubing, well valves, and connections can be diagnosed relatively easily. However, fixing them has traditionally been more difficult. Issues typically have included cost, availability of rigs or workover units, personnel requirements, leak-fixing processes, weather, and third-party dependencies. These various considerations can result in extended and long lead times to bring shut-in wells back on line or indefinite postponement of needed interventions on wells that are operating. There are also significant planning and logistics issues, and lengthy down-time can result. Well output could be partially or totally lost for months—affecting production quotas and revenue targets—before a rig is mobilized and deployed. And rig workovers can be complex and risky. Removing a well-head during a workover, for example, could affect well integrity and bring about health, safety, and environment (HSE) risks bigger than the problems the workover is intended to remedy. Brinker Technology has recently developed a system called Platelets, a rigless, through-wellhead workover technology that allows the major planning, logistical, and downtime issues of traditional work-overs to be avoided and commensurate cost savings to be achieved. In concept, the technology functions similarly to the way the human body responds to cuts and wounds, where platelets in the blood are drawn to the cut and create a seal. The oil and gas technology is designed around free-floating, discrete particles conveyed by means of an inert carrier fluid. The platelets deployed in this technology are specifically engineered for the size of the leak and the operating conditions of the system. Platelets are pumped down-stream while suspended in the carrier fluid and, when they reach a leak, pressure-differential forces entrain them into the defect to create a mechanical seal (Fig. 1). The polymeric and elastomeric materials incorporated in the platelet technology produce a seal more durable than steel and have no negative effects on the treated infrastructure. The platelet technology previously has been applied in subsea pipelines and water-injection systems. Its applications have now been extended to casing, tubing, well valves, and connections. The technology includes specific designs for both static- and dynamic-sealing applications. Additionally, by incorporating specially designed software, the technology can be used diagnostically to locate leaks (Fig. 2).

Valuing Future Information Under Uncertainty Using Polynomial Chaos

This paper estimates the value of information for highly uncertain projects whose decisions have long-term impacts. We present a mathematically consistent framework using decision trees, Bayesian updating, and Monte Carlo simulation to value future information today, even when that future information is imperfect. One drawback of Monte Carlo methods in multivariate cases is the large number of samples required, which may result in prohibitive run times when considerable computer time is required to obtain each sample, as it is in our example. A polynomial chaos approach suitable for black-box functions is used to reduce these computations to manageable proportions. To our knowledge, this is the first exposition of polynomial chaos in the valuation literature. In our example it provides a speed-up of more than two orders of magnitude. We demonstrate the approach with an oilfield example involving a future decision on where to place a new injection well relative to a fault. The example considers the value to the asset holder of a measurement, to be made in the future, that reveals the degree of reservoir compartmentalization caused by this fault. In conditions of high demand for rigs and other scarce capital-intensive oilfield equipment, it may be appropriate for the asset holder to agree to a forward contract for this critical measurement to be taken at a future date at some specified price. The service provider would be contractually bound to provide this measurement at this pre-agreed price within a specified time window, regardless of the prevailing price and availability of rigs and equipment. Despite the presence of financial uncertainty on future oil price and private uncertainty on reservoir variables that are largely unresolved by the measurement, our methodology provides a computationally efficient valuation framework, possibly leading to novel ways of setting up contract terms.

Oil and Gas Developments in Northern Rockies in 1977

In 1977 the Northern Rockies experienced a 12% increase in total wells drilled compared to 1976. Development of large stratigraphic pools and the search for new reserves of natural gas pushed the number of wells drilled to 1,407 in 1977 compared with 1,103 in 1976. Exploratory success increased from 15.6% to 23.7%; however, development success decreased from 68.2% to 56.0%. At year end, activity was still increasing although rig availability was a limiting factor.

Developments in Southeastern States in 1974

Onshore 1974 drilling activity in Mississippi, Alabama, Florida, and Georgia increased 9.7% from 1973. A total of 566 tests was drilled compared to 516 in 1973. A 20.9% increase in exploratory drilling was recorded as 370 tests were reported, 64 more than in 1973. Development activity continued to decline, however, as 196 tests were drilled in 1974 down from 210 in 1973. A total of 20 new-field discoveries was completed, 3 less than the 1973 total. New-field success rate was low at 6.1%. Exploration increased considerably in the Wilcox trend of southwestern Mississippi and it replaced the Jurassic as the leading drilling trend. Drilling for Jurassic objectives was the lowest since 1968, but some of the more significant discoveries were reported in this interval. The Paleozoic trend in the Black Warrior basin was the third most active drilling area, followed by the Upper Cretaceous, but important discoveries were lacking in both trends. Activity dropped in the Lower Cretaceous trend but 2 important discoveries were recorded and increased interest in this trend is expected in 1975. Drilling in the Mafla offshore area began at about midyear and approximately 15 Tertiary and Cretaceous tests were drilled. Only 1 successful wildcat was announced and this was less than 1 mi from established production in the Louisiana offshore area. The remaining offshore wildcats were disappointingly dry, including 2 on the huge Destin anticline of offshore Florida panhandle. Deeper Jurassic sections were not penetrated offshore in 1974. Seismic activity declined in the southeastern states in 1974. Much of the activity was detailed work supplementing data acquired in previous years. Important leasing activity occurred in the Lower Cretaceous trend and along the coastal counties of Mississippi, Alabama, and Florida panhandle where the deep Jurassic was the primary objective. Overall, however, no extensive blocks were assembled and leasing appeared to be mainly a continuation of efforts started in the previous 2 years. Total drilling activity is predicted to increase slightly in 1975 because of an expected rise in exploratory drilling. However, this forecast is based on the availability of rigs and pipe, plus continued economic incentives. Conditions or policies adversely affecting these factors could lead to a decline in drilling activity.

OIL EXPLORATION IN NEW ZEALAND—PAST AND FUTURE TRENDS

The earliest lease for oil prospecting was granted in 1865, and the first bore went down in 1866. Since then and up to 1936, 130 wells were drilled mainly in Taranaki, the East Coast of the North Island and the West Coast of the South Island. No commercial field was discovered, but some oil and gas was found sporadically — sometimes enough for local small-scale consumption — which kept interests alive.The Petroleum Act in 1937 vested all petroleum prospecting and mining rights in the Crown; with minor modification, it has regulated exploration to the present day. The war-time years saw renewed activity by several major companies; the first seismic surveys were undertaken, and some 20 holes were drilled. But except intermittent, small production from the Moturoa field in New Plymouth (the she of the first well of 1866), no further success was achieved and exploration ceased after 1944. The present period of activity started in 1955. On land the Kapuni gas-condensate field was discovered in 1959, and offshore the much larger Maui field in 1969. Both are in the Taranaki Basin which, having the best prospects in the country, has also received far more attention than other areas.Land operations sharply decreased after 1965 when Shell and BP, the only majors with on-land interests, began concentrating on new offshore holdings while still retaining their original big land concessions. Amongst the increasing number of independents continued regrouping of interests, farm deals, etc., have become common, and these companies account for nearly all activity on land during more recent years. Practically all drilling after 1965, which from a 5,686 ft. low in 1966 increased to 28,741 ft. in 1969 and 16,952 ft. in 1970 (the smaller 1970 figure is mainly due to rig shortage), was done by companies other than Shell-BP, many of them newcomers. Since to these the more promising prospects have been unavailable, exploration has noticeably shifted to areas of lesser and even marginal prospects.Concessions have for a number of years covered all lands of even remotest possibilities; the total area leased is around 50,000 sq. miles.Offshore the first concessions were granted in 1965; in 1970 they covered 384,547 sq. miles. Extensive geophysical surveys followed nearly immediately, and the first well was spudded by Esso in October, 1968. The second well, by Shell in March, 1969, discovered the large Maui field, later confirmed by two step-outs. Up to November 1970, 10 offshore wells with an aggregate footage of 101,181 ft. were drilled.I he only offshore rig now has left but additional targets are already established, and more will undoubtedly be after seismic surveys presently in course. Offshore drilling is expected to resume as soon as possible, particularly in concessions soon to expire. In large areas only recently granted, however, excessive water depth of up to 1000 m will prevent drilling for probably many years.On land, the tendency for wider participation in joint ventures is likely to continue. Increased activity by small operators is expected, as domestic rig availability has improved and many concessions are nearing expiry date. New licences to be granted over Greymouth and Canterbury areas which have drawn many competing applications should further stimulate the picture. Since Shell-BP in 1970 finally farmed out their large block in Taranaki which still holds the best prospects and many unexplored features, new operations are expected also there before expiry in 1973; BP-Shell's East Coast holdings expire in 1972 and the future of these two blocks which since 1955 have been in the hands of the same consortium, will probably be most important to further developments in New Zealand.

The Application of Permanent Completion Techniques To Offshore Operations

Abstract To reduce the cost of workovers at offshore locations, several techniques using concentric tubing strings and/or wireline methods, and/or treatments (excluding installation of gas lift valves or acidizing) performed directly down the production tubing have been field tested. Low fluid loss cement slurries have been used to complete deeper below a single zone production packer by squeezing the existing perforations, washing out excess cement and perforating the new zone with an expandable gun. higher recompletions (both below and above a single zone production packer) have been successfully accomplished using the same principles. Sand production has been stopped through the use of epoxy resin solutions displaced either through concentric tubing strings or directly down the production tubing. Plugback operations using dump bailers have been disappointing, but further work in required before this method can be condemned. Results to date are encouraging, and open a way to reduce production maintenance costs at distant deepwater locations. Introduction The average oil or gas field occurring in the Miocene and Pliocene sediments of the offshore U. S. Gulf Coast contains multiple reservoir. Realizing maximum returns from investments requires optimization of two quantities:reduction of direct operating costs. andmaintaining all wells in a continuously producing capacity until all horizons are depleted. To attain this ideal, recompletion of depleted zones or, if economically feasible, the reestablishment of production from the existing completion must be undertaken at minimum cost and with a minimum of delay. During extensive development programs, primary drilling activity tends to take precedence over production maintenance which results in an insufficient number of deepwater rigs being available for the work at hand. While capital expenditures for new development may enable production to maintain an over-all upward trend, production from older fields frequently declines to a level that is lower than necessary because deficient or off-production wells have not been worked over promptly. Rig availability is not the only factor responsible for such delays. The cost of moving an offshore rig into a field is high (between $10,000 and $50,000, depending on the length of the move and type of rig). Single well workover programs may not be economical and it is often necessary to accumulate a series of projects before a profitable workover program can be attempted. To help in solving the problems created by these restraints, workover operations using permanent completion techniques have been adapted for use at marine locations. In this paper, permanent completion techniques are defined as remedial operations which can be conducted without physically disturbing the original downhole mechanical condition of the well. This type of workover involves the use of concentric macaroni tubing strings and/or wireline methods and/or treatments (other than installation of gas lift valves or acidizing) performed directly down the production tubing. Small rigs or pulling units capable of handling the necessary tubular equipment and easily installed on well jackets or platforms are available with little delay at relatively low cost. The small units usually work 12 hours a day, handle tubing in singles and can be installed on location for about $5,000. Research into cement technology has developed low fluid loss slurries which retain fairly constant properties throughout their entire pumping time. Physical properties of such cements enable them to be pumped safely through small openings and small diameter (3/4 in. ID) work strings. Successful recompletions above and below existing perforations have been made, sand controls installed and repaired and small milling operations undertaken. These procedures have resulted in the profitable acceleration of recompletions at reduced costs and the restoration of production from sanded up wells. They have also enabled high-risk recompletions to be attempted in zones which, but for these lower cost techniques, would have been abandoned without testing. Permanent completion workover operations offer attractive economic advantages over conventional methods and enable high risk zones to be exploited. JPT P. 1031ˆ