A suite of subsea intervention case histories at the Bacchus oil field in the North Sea will demonstrate how one operator matured intervention planning to address well entry challenges using learnings gained over the course of successive jobs. This contributed to better management and mitigation of potential risks leading to slickline performance improvement for gas lift valve reconfiguration, the successful deployment of coiled tubing to clean out asphaltene deposits in a live subsea oil well from a monohull vessel and setting of a retrofit gas lift straddle to optimize and secure production. The paper outlines intervention asset selection, work programme development and risk mitigation measures related to subsea tree valve function issues and loss of full bore access caused by asphaltene and wax deposits. Light well intervention vessel and mobile rig operations using deployment methods including slickline, digital slickline, electric line and coiled tubing are described. The role of production technology work undertaken to better understand the nature of organic deposits in the wells and how that contributed to anticipating well access risks and inform intervention planning will be highlighted. These real field examples add to the knowledge base of well services and production technology challenges faced during subsea well intervention and highlights approaches to overcome them.
Khoramfar, Shooka (Department of Environmental Engineering, Texas A&M University-Kingsville) | Jones, Kim D. (Department of Environmental Engineering, Texas A&M University-Kingsville) | Boswell, James (Boswell Environmental) | King, George E. (Apache Corporation)
Biological based emissions control has been demonstrated to be an efficient and cost effective alternative to thermal oxidation technology or flaring for volatile organic compounds (VOCs) from the forest products and paint and coatings industries. This type of technology applicationhas promising advantages such as the potential for a low carbon footprint, low secondary pollutants such as NOx and SOx, lower energy demands, and lower cost. The objective of this project was to design and implement a sequential field scale biotrickling-biofilter treatment unit to remove VOCs and hazardous air pollutants (HAPs) emissions at the Apache TAMU#2 well storage tank battery in Snook, Texas.
The field scale biotreatment system included a biotrickling filter followed by a biofilter with the total treatment volume of 100 ft3, skid mounted on a 22 foot trailer. The biotrickling filter was packed with structured cross flow media with large surface area and high void fraction designed to remove the more water soluble compounds and control the humidity and temperature variations of the inlet gas stream. The biofilter unit was loaded with plastic spheres packed with compost which is referred to as the engineered media. Each of the bio-oxidation units was operated at the air flow rate of 25 CFM and empty bed residence time (EBRT) of 2 minutes. The system was inoculated with local stormwater and wastewater from a sedimentation basinclarifier of a local refinery to provide a mixed culture of microorganisms for degradation of the VOC emissions.
VOC emissions were collected from the headspace of a storage tank battery leading into a pressure relief vent system. Based on the photo ionization detector (PID) measurements at the inlet of the bio-oxidation unit, the VOC concentration loadings was cyclic and appeared to be correlated to the gas lift cycle of liquid loading to the crude oil storage tank.
During the evaluation period, the biotrickling unit demonstrated a surprisingly higher removal efficiency compared to the biofilter. This may be related to the more stable and higher density of biomass growth observed on the surface of the cross flow media. The lower removal efficiency in the biofilter unit could be due to the lack of uniform moisture and nutrients in the second vessel as a result of spray nozzle inefficiency. This aspect of operation can be further optimized by changing the nozzle and the frequency of watering/spraying of the compost media. A removal efficiency of 50-60% for the total VOCs, across the complete unit, was achieved during the 3 month evaluation period while the unit was operated at an average inlet VOC concentration of 400 ppm.
The relatively high concentration of alkenes and alkanes (compared to aromatics and water soluble organics in this crude oil vapor), may have decreased the degradation of the total VOCs in the bio-oxidation unit because these long-chain compounds are more difficult to biodegrade by bacterial biofilms in an aerobic environment.
The results suggest biological emission treatment systems may be cost effective when compared to thermal oxidizers and flares and should be evaluated as a Maximum Achievable Control Technology (MACT) to mitigate HAPs (and VOCs) from some oil and gas operations.
This innovative biological emissions control technology effectively controlled the cyclic emissions produced at the remote site. The strong increase in removal of VOCs after the oil refinery wastewater inoculation suggests an important optimization parameter for more rapid acclimation and increased efficiency for the system in the future applications.
Frac hits or "frac bashing" is a fracture-initiated well-to-well communication event that can create production losses (or gains), and on occasion, mechanical damage when frac energy from a stimulated well extends into the drainage area or directly contacts an adjacent or offset well. Pressure increases have been detected in wells at distances ranging from hundreds to thousands of feet from the stimulated well. While these in-zone frac hit events do not pose an environmental problem if there is no failure of containment, there can be some alteration of the production potential in one or both of the wells involved.
Frac hits along the preferential fracture plane were an uncommon but known event when the completion method only involved vertical wells, but the rate of incidence has increased sharply as the preferred completion method has shifted to relatively closely-spaced, multiple fractured horizontal wells (MFHW) in low permeability formations such as the mudstone rocks commonly referred to as shales.
Mechanical damage within the well and success of methods of prevention, damage control and remediation will be examined by case histories and published contexts of incidents in several basins, but will not be the main goal of the paper.
The primary effort will focus on examining causes of production loss and duration of the loss, including looking at production declines pre-hit and post-hit. Known causes include in-situ stress alteration potential, timing of fracture closure, near-wellbore proppant loss, liquid loading, rock-fluid interactions, sludges and wetting factors. Also considered will be geological effects such as regional fractures and linked natural fracture clusters. A main objective will be to identify pressure transient, chemical analysis or other monitoring techniques to identify location and type of damage.
Remedial operations are most effective when the potential cause of production losses can be ranked probabilistically and the depth of the production-reducing event can be estimated as near-field or far-field. Analyzing this data will also assist in defining whether chemical or mechanical treatments such as refracturing or a hybrid treatment system may be the best approach.
Sankoff, Roumen Dimitrov (Apache Energy Ltd.) | Di Martino, Gianluca (Apache Energy Ltd.) | MacDonald, Shona (Apache Energy Ltd.) | Marshall, Craig Scott (Apache Energy Ltd.) | Smith, Anthony (Apache Energy Ltd.)
The development of heavy oil accumulations presents difficult engineering, technological and geological challenges that need to be overcome to produce economically viable projects. Even a large oil accumulation can be deemed unattractive for development in cases that combine a high cost environment with complex geological setting and unfavorable fluid dynamics. This paper highlights the challenges and presents the subsurface solutions that unlocked the value of an offshore heavy oil accumulation, 32 years after it was first discovered. Within the context of the overall development plan, the paper describes:
1. The design of the offshore well test that delivered 11,244 bbl/d 15.7oAPI oil and proved the production capacity of the reservoir and the conceptual well design.
2. Workflow for confirming the existence of a compositional gradient and characterization of a biodegraded oil column.
3. A novel approach to evaluation of inflow control devices (ICD) and its implementation in the well design.
4. An ICD modelling tool developed specifically for direct comparison of different ICD geometries.
The paper also presents the field history to date - from the early failures in recovering hydrocarbons using conventional methods, through to the enabling technologies that made Coniston and Novara a viable project.
Coniston and Novara reservoirs are located in permit WA-35-L, offshore Western Australia (Figure 1). Apache holds 52.5% working interest and operates the permit on behalf of a joint venture with INPEX which holds 47.5%. The joint venture acquired the permit in 2009, 27 years after the field was discovered with the drilling of Novara-1 in 1982. The fields are 45 km from the coast of Western Australia (Figure 1) in 380 m water depth and will produce 14-16oAPI oil from the Barrow Group formation.
The reservoir contains a thin oil column between a small gas cap and strong bottom-drive aquifer. The oil will be produced via subsea tie-in to an existing production system and a floating production, storage and offloading facility (FPSO), the Ningaloo Vision (NV), located approximately 10 km away.
The project was challenged by (1) unproven well and reservoir capacity to deliver production at commercial rates, (2) heavily compartmentalized low relief reservoir structure, (3) water and gas coning affecting recovery from a thin oil column, (4) a strong bottom-drive aquifer impacting the wells’ drainage area and (5) flow assurance and operability issues due to long distance subsea tie-back.
Production at commercial rates from each reservoir was demonstrated in the early phase of the appraisal campaign. The flow tests met all objectives, and set a record for the region with the Coniston-2H well testing at 11,244 bbl/d of 15.7oAPI oil. The successful production tests were followed up with further appraisal wells to delineate the structure. The results from the appraisal drilling revealed: a low-relief structure, complex fault network, lateral variation in the fluid contacts.
Meli, Ricardo (Apache Energia Argentina) | Salas, Carlos (Schlumberger) | Martin, Rodrigo (Schlumberger) | Roa, Edwin Restrepo (Schlumberger) | Nervi, Virginia (Schlumberger) | Zaheer, Aamer (Schlumberger) | Durairajan, Bala (Schlumberger) | Hill, Richard (Schlumberger)
Apache Corp recently commenced horizontal drilling activity to develop shale gas reserves in Neuquen basin, Argentina. On one well, the curve was drilled with a 12¼-in PDC bit on PDM. The lateral was drilled with an 8½-in PDC on a point-the-bit RSS. A motor BHA was used in the curve because standard RSS could not deliver the required DLS. To optimized operations, Apache wanted to complete the curve and lateral with a single 8½-in PDC. However, the lack of high-build rate RSS required the curve still be drilled with a motor building to 50° then tripping for a point-RSS to TD the lateral. The single diameter strategy was successfully executed but further NPT reduction was still possible.
The challenge was to drill the curve/lateral with a high build-rate RSS and a single 8½-in PDC in one run to eliminate a trip to change the drive system. The introduction of an inclination hold and azimuth software system would enable the RSS tool, created to build the aggressive curve angle, to continue efficiently drilling in the lateral saving an additional trip. An engineering analysis was then launched to design an application specific PDC for the RSS. A FEA-based system was employed to analyze offset BHAs, directional profiles, bit hydraulics and mud properties. The study revealed the baseline PDC was delivering excellent ROP in both the curve/lateral, but modifications would be required to increase the bit’s dynamic stability. A modified 8½-in SDi513 was proposed that features a customized cutting structure and tapered gauge for improved stability.
Next, a rock strength analysis was used to determine characteristics of lithologies encountered in the field. The study determined Quintuco (curve) and Vaca Muerta (lateral) have relatively low UCS (3-15 kpsi) but vibration potential in Quintuco is moderate. Computer simulations were run to map lateral/axial acceleration and bit torque on RSS. The results showed the new design displayed a significant increase in dynamic stability compared to the baseline bit with similar high ROP potential.
The shale optimized BHA drilled 1289-m of curve and lateral in one run at a record ROP of 9.64 m/hr, 35% faster than the offset average. The high build-rate RSS landed the wellbore at 96° with a maximum turning radius of 11.8°/30m increasing reservoir exposure within the acreage unit. The increased ROP enabled Apache to reach TD seven days ahead of plan for a savings of $595,000USD.
Trent Jacobs, JPT Technology Writer Early in its development, the Cline shale was hyped as the next Eagle Ford or Bakken with more oil and gas than they have combined. The lofty projections of the Cline shale's potential, located in west Texas on the eastern side of the Permian Basin, were extrapolated from information presented by Devon Energy to financial analysts in April 2012. At that time, the company's data regarding the emerging play suggested the possi bility that as much as 3.6 billion BOE lie trapped within Devon's 500,000 acres of Cline shale. Analysts looking for North Ameri ca's next major unconventional resource then calculated that the entire forma tion, roughly 140 miles long and 70 miles wide, held between 30 and 35 billion BOE, which would make it one of the largest discoveries in the world. That hasty estimate did not take into account how much of the potentially mammoth resource could be economically recoverable.
Copyright 2012, SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production This paper was prepared for presentation at the SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production held in Perth, Australia, 11-13 September 2012. This paper was selected for presentation by an SPE/APPEA program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers or the Australian Petroleum Production & Exploration Association Limited and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers or the Australian Petroleum Production & Exploration Association Limited, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers or the Australian Petroleum Production & Exploration Association Limited is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Real time digital slickline services have been used increasingly in the Gulf of Mexico by a number of customers. Through its telemetry enabled capabilities and the purpose built tools that complete the platform, digital slickline services can deliver a number of safety and efficiency gains to all types of slickline operations.
Material presented in this paper will be from actual operations, examples being perforation, tubing punching and cutting, plug setting and cement dump bailing, and will demonstrate the operational efficiencies being delivered.
Enhancement of the slickline service comes from real time surface readout of in situ tool operational status, the critical core measurements of downhole toolstring movement, deviation head tension and shock, and the depth precision now offered through gamma ray and CCL sensors. Optional tools such as a pressure / temperature gauge bring yet further visibility on the impact of the downhole actions undertaken. Expansion of the slickline service capabilities come from the telemetry enablement and core tools, coupled with a range of specific tools and sensors that have been developed to run on this slickline platform, namely a electro-hydraulic setting tool, an explosive triggering device, a monobore lock mandrel, and a production logging suite.
The real time data that is delivered to the slickline operator removes the need for assumptions that often have to be made during conventional slickline operation, and allow for a more efficient and reliable slickline operation to be undertaken. This results in a reduction in operation time, and a reduction in unnecessary trips out of the well to check on the tool status or to validate depth. Furthermore, since digital slickline is able to carry out both slickline well preparation work and a range of remedial or measurement work often carried out on memory or eLine, these operations can often be conducted entirely utilizing digital slickline crew and equipment. This optimizes pre- and post-job logistics, equipment rig up and rig down, and the job execution itself. In addition to the obvious cost savings, with a slickline wire comes a simplification of the pressure control and a well control recovery situation.
Management of gas reservoirs can be a difficult task if there is a varying degree of interference between wells. This difficulty increases with well count and the number of compressors and inter-connected processing plants. Numerical simulation of the integrated network and reservoir can help substantially. However, stability issues in complex networks and extensive data requirements have made simulation costly for large and complex projects.
With an extremely stable and efficient numerical model combined with data preparation techniques that rely on the use of existing databases and automated techniques, as well as streamlined history matching approaches, it has now become economically viable to use integrated models for large shallow gas properties. Without such a model to predict future performance, there is significant risk of over-building and over-drilling for future development. This paper discusses the setup, calibration and day to day use of an integrated model for a shallow gas field in Southern Saskatchewan, Canada.
The Hatton reservoir has three main productive geological zones, all of which are of low permeability. As of October, 2001 the Hatton gas field in this project contains over 2900 wells with 38 years of production history. Production from the field began in 1964 and was taken over by Fletcher Challenge Energy in the late 1960's. Rapid development started in 1986 and has continued to the present. The field has since been acquired by Apache Canada Limited.
This field has three shallow Cretaceous gas zones, Milk River (MR), Medicine Hat (MH) and Second White Speckled Sandstone (SWS). The MR and MH zones contain shale and silt layers with sandy lenses. The MH pay is all at the top of the formation immediately below the MR. The Milk River and Medicine Hat zones have very low permeability and produce at low rates while the SWS zone has higher permeability and produces at higher initial rates. Productive Milk River exists over the entire field while the Medicine Hat pay disappears to the east and the productive SWS exists only in the extreme south. While the three zones are still segregated in some wells it is now common practice to commingle the upper two zones and segregate the SWS. The Milk River-Medicine Hat well spacing varies from 64.7 to 32.4 ha (160 to 80 acres) while the SWS spacing varies from 259 to 64.7 ha (640 to 160 acres). The main part of the field has been developed under closer spacing and most of the remaining reserves are in the Milk River zone as the other productive zones have less net pay thickness and area and had higher initial producing rates.
In the year 2001 program 200 wells were added and in 2002, a 600 well infill program was initiated. At the end of October, 2001 there were 1846 wells producing out of a total of 2136 wells in the Apache operated area. The surface network in Hatton is very complex with multiple delivery points, compressor stations and significant flow splitting. There were four sales points and six compressor stations, two of which were boosters. The maximum rate for the Apache wells in this field reached 4000 E3m3/d during the late 1980's and has since decreased to approximately 1500 E3m3/d.
The original model for this field was built in 1993 using a "pseudo well" model where wells associated with a given battery were grouped and averaged into tank reservoirs. Gathering lines connected these pseudo wells to the compressors and plants. This model was limited because of the use of tanks to represent reservoirs, where new wells may start at lower pressures than actual. In addition, pressure drops along group lines are not properly accounted for and uncertainty existed in the calculation of effective diameters for the pseudo wells.
With improved computer performance and simulation programs it is now practical to model such a system on an individual well basis with reasonable computing times. A decision was made to build a full-scale model of the system to help plan facilities optimizations for a 600 well infill program for 2002.
A discrete reservoir surface network model was chosen to improve the field analyses. All 2136 historic wells in the Apache operation and 818 outside wells were included in the reservoir history match.
The Dual-Energy Venturi Multiphase Flowmeter (MPFM), has gained acceptance within the Oil and Gas Industry as an accurate and cost-effective solution to multiphase metering. has now been implemented by the Australian Petroleum industry on the Apache Energy Simpson Alpha, Bravo and Gibson remote mini-wellhead platforms.
Eliminating the conventional test separator has led to wide-ranging improvements in engineering, financial and Operations areas. In addition, the field data are being used in a wide range of new and beneficial applications, including new field development, rapid deployment, artificial lift optimization and well-clean up optimization operations.
Integration of the MPFM packages into Customer supervisory control and data acquisition system (SCADA) and the connectivity achievable through these compact metering packages, has shown the benefits the customer may obtain by providing real-time data to operations and reservoir critical management functions. Connectivity for remote fault diagnosis and maintenance actions significantly reduces Field Service Operational Expenditure (OPEX) costs, and nonproductive time for field service personnel, which is particularly beneficial for installations in areas that lack infrastructure.
The applications, and commissioning of the MPFM packages and other low-cost technologies are illustrated in the paper. The straightforward nature of the Vx* multiphase well testing technology installation process brings distinct advantages to these applications, provided that methodical preparation is performed beforehand.
The key to the success of the multiphase flowmeter, as a tool for well performance diagnostics and production optimization, is its high availability and long-term performance stability, underpinned by the local and regional support network available to customers.
In the future, challenges remain in the interpretation of the new information being gathered, which document previously unrecorded inflow and outflow behaviors, with unmatched resolution and dynamics.
Multiphase flowmetering can demonstrate wide-ranging benefits over conventional Test Separators. While the minimization of capital expenditure and engineering achieved by adopting a multiphase approach to well testing are clear, the potential benefits that may be attained with the MPFM by providing real-time data acquisition and remote connectivity still need to be quantified. It is the aim of this paper to identify some of these benefits.
The principle of operation of the Dual-Energy Venturi Multiphase Meter has been the subject of numerous previous publications, and is included in the Appendix 1, for reference.
In 2001, Apache Energy embarked on the Simpson field development, consisting of two remote mini-wellhead platforms, located 2 km from the existing Varanus Island processing facilities. Key objectives for Apache Energy in the field development plan for Simpson field are listed below:
To minimise field development capital expenditure (CAPEX) costs (through size, weight and footprint reductions)
To limit the facility weight, such that the entire topsides could be supported by the well production casings without need for additional structural members.
To provide interface for remote control and monitoring of the platform equipment and facilities, reducing the number of platform visits required during operations.
To minimize equipment installations on the facilities, and therefore the requirement for platform visits to undertake maintenance actions.
By using MPFM technology, the installed wellhead platform topsides were designed with PhaseWatcher* fixed multiphase well production monitoring equipment in the individual well flowlines, thus eliminating the requirements for a conventional test separator.