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Abstract A number of tools are available for production improvements for wells where the cost of workover rigs cannot be justified or where workover rigs are unavailable. Recent literature has described some through tubing and rigless type workover innovations. This paper presents case histories explaining the use of production logging, coiled tubing, small bridge plugs, cement packers, acidizing and oriented perforating methods that resulted in excellent gas and oil production increases. Significant savings were experienced when compared to more conventional rig supported workovers. Cement packers placed by coiled tubing and oriented through tubing perforating have been used in several cases to restore inactive wells to commercial production rates. This paper describes two such attempts. In another case, extraneous water production was identified with a production log and shut off with a simple bridge plug setting. This was followed by acid stimulation of the gravel pack to restore the damaged interval to good gas rates. A third case is also presented to show several problems that were encountered in an older well. In order to select the appropriate technique and achieve the best results, a clear understanding of the problems, the objectives, and the available tools is needed for each case. This was accomplished by use of a multi-disciplinary team of various operating company and service company professionals involved in, the design and field operations to thoroughly review each proposal. Introduction VICO Indonesia operates several oil and gas fields in an area of East Kalimantan approximately 140 kilometers north of the city of Balikpapan (Fig. 1). These fields are operated under a production sharing contract with Pertamina, the Indonesian national oil company. VICO is the operator of a joint venture that began in the late 1960's and discovered commercial oil and gas in early 1972. Today the production rates are approximately 1.7 billion cubic feet (Bcf) gas, 40,000 bbl of condensate and 30,000 bbl of oil per day from VICO's four major fields. Gas is transported and sold through the liquification (LNG) plant at Bontang, and the liquids are blended and sold via the tanker terminal at Santan. Badak, the largest and oldest field, has now been completely developed by drilling. Because of the large number of reservoirs penetrated by wells in this field, workover operations will continue for many years to recomplete into shallower zones and repair existing completions. Now, in efforts to maximize the use of all wellbores and considering cost containment issues, production engineers at VICO have designed and performed several unique work programs that utilize rigless methods at a cost of about one-third the cost of similar rig supported workovers. These programs involve the use of production logs, coiled tubing, special cementing techniques, oriented perforating, inflatable packers, acidizing cement packers, computer modelling, small diameter tools, etc. Generally, very good success has resulted from the overall program. Gas production was increased by 130 million cubic feet per day (MMcf/D) and oil rates improved significantly in 1995. A few unexpected problems were encountered and these are also discussed. TDT Log, Coiled Tubing cement Packer, Oriented Perforating - Badak Well number 121 The original completion for Badak well number 121 was a dual gas well. By 1993 both zones had watered out, but interest in a zone behind casing led to a thermal decay time (TDT) log survey (Fig. 2). This survey showed that the three zones in the B-12 reservoir were not uniformly depleted since the middle interval was wet while the upper and lower sections contained gas. P. 35
- Asia > Indonesia > Kalimantan (0.24)
- Asia > Indonesia > East Kalimantan (0.24)
Abstract The hydraulic system plays an active role during drilling operations. Its proper design can accelerate the drilling effort and lower the overall well cost. It is very important to predict the exact pressure distribution along the well and the circulating temperature distribution in the fluid. This paper describes an innovative hydraulic computer program developed in Agip. The program calculates the rheological parameters of drilling fluid based on the viscometer readings. The rheological models of Newton, Bingham, Power law and Herschel-Bulkley are considered. The program calculates also the temperature profile of drilling fluid and takes into account the temperature effect on the rheological parameters, when available viscometer readings at different temperatures. The use of Herschel-Bulkley model and the temperature effect estimation improve the flow modelling capability during drilling fluid circulation and permits to better study and quantity the influence of hydraulic parameters, thus allowing better planning. It will be also considered case histories with comparison of calculated and field data coming from Agip ultradeep wells experience. Introduction The most important effects of hydraulic system on the well are:–control subsurface pressures; –evaluate pressure increases in the wellbore during mud circulation; –remove cuttings from the well; minimise hole erosion due to the mud washing action during circulation; –increase penetration rate; –size surface equipment such as pumps; –provide a buoyant effect to the drillstring and casing; –control surge pressures created by lowering pipe into the well; –minimise wellbore pressure reductions from swabbing when pulling out of hole the pipe. P. 77
- North America > United States (1.00)
- Europe (0.68)
- Asia (0.68)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract The Caño Limon Field, discovered in 1983, is the giant oil field that made Colombia self-sufficient in oil. The field contains over a billion barrels of recoverable oil, and as of publication date, has produced over fifty percent of its reserves. The current production rate is 215,000 BOPD. Sound reservoir and production management has resulted in an expected ultimate oil recovery of about 58 percent of the Oil-in-Place. The field has a current watercut of 80 %, thus, the operator is managing the high disposal of large volumes of produced fresh water (over a million barrels per day) with minimum impact on the environment. This has been accomplished by treating and disposing the produced water with compliance of strict environmental guidelines. High recovery factors have been achieved by the implementation of technologies such as those listed below: Reservoir management techniques used to define new well locations and strategically select completion and recompletion intervals by:making extensive use of a 3-D simulation model, and implementing a well defined program of reservoir monitoring using production logs, single well pressure tests and multiwell interference tests. Experience with state of the art electrical submersible pumps (ESPs) and variable speed drives (VSDs) in lifting large fluid volumes, up to 22000 BFPD per well, with associated sand production ranging from 0 to 200 ppm. This has enabled high oil production rates to be maintained, and oil recovery to be maximized in spite of the high watercuts associated with this very active water drive field. ESP completions with Y-tools are strategically placed to provide for the ability to perform reservoir monitoring surveys. Automated and continuous well production measurement techniques (rates and watercuts) are used to monitor individual well performance, allowing for the implementation of corrective actions in a timely manner. Treatment and disposal of the large amount of produced water in compliance with strict environmental guidelines. The field is located on the eastern edge of the Llanos (plains) of Colombia, in an ecological area that can be described as flood plains. This area is normally flooded during the rainy season from June through October. Measures are taken to restore and maintain the natural environment of the area.
- South America > Colombia > Arauca Department (0.85)
- South America > Argentina > Salta Province (0.62)
- South America > Colombia > Meta Department > Llanos Basin > Cano Sur Block > Carbonera Formation (0.99)
- South America > Colombia > Arauca Department > Llanos Basin > Cano Limon Field (0.99)
- South America > Argentina > Salta > Noroeste Basin > Limon Field (0.99)
- North America > United States > Texas > Permian Basin > Area Formation (0.99)
Development And Trial Of Microwave Techniques For Measurement Of Multiphase Flow Of Oil, Water And Gas
Ashton, S.L. (CSIRO Division of Mineral and Process Engineering) | Cutmore, N.G. (CSIRO Division of Mineral and Process Engineering) | Roach, G.J. (CSIRO Division of Mineral and Process Engineering) | Watt, J.S. (CSIRO Division of Mineral and Process Engineering) | Zastawny, H.W. (CSIRO Division of Mineral and Process Engineering) | McEwan, A.J. (CSIRO Division of Mineral and Process Engineering)
Abstract A prototype microwave and gamma-ray MFM has been developed for measurement of oil, water and gas flowrates on production pipelines and has been successfully trialed at the Thevenard Island oil production facility. The microwave and gamma-ray MFM determined the oil and water flow rates with errors of 5.4 and 5.9% relative respectively for the wide range of wells and flow conditions during the trial period. A prototype non-intrusive microwave MFM is being developed for measurement of oil, water and gas flow rates on production pipelines. The microwave MFM will be trialed on the West Kingfish platform in Bass Strait in late 1994. Introduction Crude oil extracted from geological reservoirs is normally accompanied by gaseous hydrocarbons and water. These three components are piped from the oil well as a multiphase mixture. The flow rate measurement of the oil, water and gas from individual wells is important for better reservoir management and optimisation of the total oil production over the field life. The current practice for the measurement of the flow rate of the oil, water and gas components of the multiphase mixture is to periodically physically divert the well output to a test separator. After separation, the flow rate of each component is measured with conventional devices such as orifice plates or turbine flow meters. There are a number of inherent disadvantages with this approach. Firstly, due to cost, a single test separator usually monitors a large number of wells, and therefore it is not possible to continuously monitor the output of each well. In addition the time to monitor a single well can be quite long due to the need to obtain stabilised flow during the test. These factors combined result in infrequent testing of component flows from wells, and potentially less than optimum management of the oil reservoir. Further, the test separator and its associated equipment may contribute significantly to the cost of an off-shore platform. For the purposes of reservoir management, the oil industry requires a multiphase flow meter which is compact and capable of measuring the flow rates continuously to within about 5-10% relative. P. 681^
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Saladin Field (0.94)
- North America > United States > Utah > Island Field (0.89)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (1.00)
- Facilities Design, Construction and Operation (1.00)
Abstract It is impossible to control and adjust an oil and gas field development without determining the flow intervals of production wells. For that it is preferable to get production profiles by using the downhole flowmeter. There are, however, some main restrictions for wide-spread application of them on the offshore of Vietnam as follows:–The flowmeter spinner velocity cannot indicate correctly in the open hole wells having a ununiform diameter. –It is unable to carry out in the case when the tubing shoe is lower than top formation on 300 - 500 m. In this paper, the authors present a summary of temperature profile method to determine the flowing and intaking intervals of wells drilled in basement of the White Tiger Field on Vietnam offshore. For last 2 years more than 30 wells were surveyed by this method in the above mentioned conditions. This paper presents the theory and practice of well temperature profile surveys, the concrete examples of data interpretation using the software "Oiltest". Introduction On the offshore of Vietnam where the main production object is crystalline basement, the open bole zones of the wells are 400-600 m and more. These zones often include the caverns and choking sections with different diameter. In these conditions, the downhole flowmeter spinner indications are incorrect because the spinner velocity is correspondent to well flow velocity but last changes either including a new production layer or an interval with different diameter. Moreover in many wells the tubing shoes are run down on 300-500m lower than the production interval top. In this case tile downhole flowmeters are not applicable. Therefore the authors propose a well-known temperature profile method for the well flow survey. It is shown that this method is very useful not only for determining the flowing intervals but also for evaluating their productivity in the wells of offshore Vietnam. P. 173^
Abstract A mechanistic model for gas-liquid-liquid systems has been developed. Given the superficial velocities of the constituent phases and their physical properties, and the pipe diameter the corresponding oil and water film thicknesses in three phase stratified flow can be predicted. Experimental data has been obtained for gas velocities up to 7 m/s. The model predictions agree well with the experimental data, Introduction For subsea and remote well sites, it is often intractable to separate oil and gas there. The transportation of oil and gas in multiphase pipelines is therefore becoming more common. The oil-water-gas mixtures produced are transported many kilometers to a platform or central gathering station where the fluids are separated. Flow pattern prediction for two phase gas-liquid flow has been studied by several workers. The most widely used methods are the mechanistic approaches of Taitel and Dukler (1976), and Taitel et. al. (1980). From a knowledge of the liquid film height in stratified flow, criteria for the flow regime transitions were determined. Later, following the same approach, Barnea et al. (1982, 1985, & 1987) proposed a unified model for a wide range of pipe inclinations. In an attempt to improve these models, Lin and Hanratty (1986), Andritsos (1986) and Wu et al. (1987) applied linear stability theories to a stratified flow, especially for the transition from stratified to slug flow. This approach is inadequate for large diameter pipelines where large amplitude waves are present. P. 553^
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation (1.00)
Abstract In 1993, Australia saw a surge in horizontal well drilling and completion. This surge was motivated by two main factors: the desire to produce oil from fewer wells per field at substantially higher production rates per well, and the necessity of draining the reservoirs with horizontal wells as dictated by local conditions of formation geometry and petrophysical characteristics. One of the most efficient ways of evaluating the productivity of a horizontal drain is to run production logs in the recently completed well. The technique used is called CTL* Coiled Tubing Logging, which was first implemented in 1988 and has become routine since. Applications of production logging in horizontal wells include:initial completion evaluation, in-situ measurement of the productivity index, flow profile determination, multiphase flow regime characterization, determination of unwanted water and gas entries, dynamic reservoir characterization by pressure transient testing. Through-tubing formation evaluation tools can also be run together with the production logs to complement openhole evaluation. More than ten wells have been successfully logged in approximately one year, in different oil and gas provinces of Australia and in a variety of completion configurations. The paper describes the data acquisition programs, the downhole sensors which have been used and their application to horizontal flows. The data interpretation methodology is presented, and a number of interpreted examples are shown. The paper concludes with the relevance of production logging to the optimization of production engineering, and reservoir drainage by horizontal wells. 1) Introduction. Production logs have been run in horizontal wells since 1988. Early experience was summarized in 1990 in Ref. 1 by Chauvel et al.
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
SPE Members Abstract Conventional nuclear fluid density gravelpack evaluation tool (GPPT) was found to cause misinterpretation when run in well containing fluid of different densities. As a result an alternative tool called silicon activation gravelpack tool (SGPT) was field tested. The principle of the tool is based on detection of activated gamma ray which is produced when silicon atoms are made unstable by striking with fast neutrons. The trials were carried out in 3 wells in Bokor. In order to get conclusive results, GPPT and PLT were also run in these wells and the results compared. It was found that in wells with single phase fluid, the SGPT results were in agreement with the GPPT'S. When logging from water to oil, both tools were affected but SGPT was less affected than GPPT. The effect of water on GPPT was almost the same as the effect due to top of gravel. For SGPT, the effect due to gravel was more pronounced compared to effect due to water. When logging from oil to gas, SGPT didn't show any shift in readings whereas the GPPT was badly affected. In conclusion, SGPT was found to be more reliable than GPPT for evaluating gravelpacks when there were more than one fluid densities in the wellbore. Introduction Bokor field is situated 45 km offshore Sarawak, North West of Miri. The stratigraphy of Bokor consists of a series of sand and shales, stacked on top of one another, deposited in a shallow marine to fluviomarine environment. There are 73 oil bearing reservoirs with depth between 1500 to 5950 feet subsea. The individual reservoirs are between 5 feet and 130 feet thick. In view of the large number of relatively thin sand with similar pressures, the wells were completed on sand groups rather than individual sand units. Development in Bokor field started in 1982 and currently there are 40 producing wells. All of these wells, except one are completed as dual string and due to the unconsolidated nature of the formation, all the intervals are gravelpacked, Typical completion of Bokor well is shown in Figure 1. P. 383^
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.55)
- Geology > Geological Subdiscipline > Stratigraphy (0.54)
- Well Completion > Sand Control > Gravel pack design & evaluation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.91)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (0.76)
SPE Members Abstract The PNL/Borax log was designed as a replacement for temperature and radioactive tracer logs in identifying channels in the cement sheath surrounding the casing in production or injection wells. This isn't the only application of the log. Because of the correction for thermal neutron diffusion, it can be used to differentiate between a channel and other mechanisms of fluid movement, such as a leaking packer, leaking squeezed perforations, and gas migration under an impermeable barrier within the formation. These added capabilities can result in a better diagnosis of the well condition. With the downhole processes pinpointed, the proper kind of remedial wellwork can be recommended to optimize the performance of the well. The PNL/Borax log has been successfully used to diagnose channels (or lack of channels) in dozens of producers in Alaska's Prudhoe Bay oil field, and has been run with mixed results in injectors. It has also been used to successfully distinguish between leaking packers and channels. In addition, the borax tracer has been found to be safe to wellsite personnel, and can be produced back out of the formation to minimize impacts of future neutron logging operations. This paper presents the basic theory behind PNL/Borax logging and provides field examples of its use in producers and injectors. Introduction Movement of gas or water through channels in the cement of a producing well can seriously degrade its performance and add to its operating cost. This unwanted production, if allowed to continue, can reduce the economic life of the well and its cumulative recovery. In injection wells, the movement of gas or water through channels can result in injection outside of the intended interval. Misplaced injection can result in the loss of injected fluids into nonproductive formations and reduced efficiency in a water/gas flood or pressure maintenance program. In order to properly repair suspect wells, existence of a channel must be verified. Historically, two techniques have been used to identify channels: temperature logs and radioactive tracer logs. Both methods have limitations, and results from either log can be unclear, making recommendations for the correct type of remedial well work difficult. An incorrect interpretation of the well's problem can often result in an unnecessary or ineffective and expensive workover that may even damage an undamaged well. Pulsed Neutron Logging (PNL) uses thermal neutron decay detectors to measure how quickly the formation and wellbore environment capture thermal neutrons. This rate is inversely proportional to the thermal neutron capture cross section of the formation and wellbore environment. Pulsed neutron logging tools are used to track the movement of a saline solution of borax and water by measuring changes in the capture cross section of an interval caused by the injected borax. PNL Neutron Physics Pulsed neutron logs measure the rate of capture of thermal neutrons by the wellbore fluid, casing, cement, and formation. Thermal neutrons are created through numerous elastic and inelastic collisions with atomic nuclei in the downhole environment following a burst of fast (high energy) neutrons generated by the logging tool. Capture of a thermal neutron normally results in the emission of one or more gamma rays. The rate at which thermal neutrons are captured is measured by recording the number of gamma rays detected within specific time gates following the fast neutron burst. This rate is inversely proportional to the thermal neutron capture cross section and is represented by the Greek letter sigma (). Sigma is a measure of the target that a nucleus presents to a thermal neutron. A larger, equates to a greater probability of capture. Measurement of the capture cross section can be used to identify channels by comparing the, measured before and after a tracer (with a larger than that of the formation) is pumped into the well. P. 567^
- North America > United States > Alaska > North Slope Basin > Sag River Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)