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Search SPE Asia Pacific Oil and Gas Conference and Exhibition: 4.3.3 Solids
First Installations of the 9-5/8-in. Enhanced Single-Trip Multi-Zone Sand Control Technology in Offshore Brunei
Fourie, Bernard (Brunei Shell Petroleum) | Marpaung, Billman (Brunei Shell Petroleum) | Jansen, Rene (Brunei Shell Petroleum) | Wong, Andrew (Halliburton) | Mok, David (Halliburton) | Karlsey, Narmesh Singh (Halliburton)
...Flowback Rate (bpm) B B C 5000 10 10 9 9 4000 8 8 Screen Out 3700 Psi 7 7 3000 6 6 5 5 2000 4 4 3 3 1000 2 2 1 1 30 31 0 0 04:35 04:40 04:45 04:50 04:55 05:00 05:05 11/11/2011 11/11/2011 Time...
...assembly was run on drill pipe to deburr the perforation tunnels and to circulate the brine until a solids content of less than 0.05% was achieved. The sand-face assembly was run in the following sequence: ...
Abstract Brunei Shell Petroleum (BSP) operates the mature South West Ampa (SWA) and Bugan Fields in Brunei Darussalam. The fields, located 10 to 21 kilometers offshore Brunei in water depths ranging from 10 to 40m, are major sources of oil and gas production. Controlling sand production is a key completion challenge as the reservoirs are composed of multilayer unconsolidated sands, requiring sand control for safe production. Cased-hole, stack-pack systems were considered as the default solution for shallow reservoir zones and wells. Due to the reduced production rates in some reservoirs in the fields and increasing rig costs there is a demand to improve the cased-hole gravel pack efficiency. The wells require zonal isolation and sand-control treatment. Cased-hole stack packs have been a reliable completion method, due to their capabilities for better zonal isolation and multi-zone functionality. Due to the reduced production rates in the mature fields, however, wells were no longer considered economically feasible. Therefore, BSP decided to try a new 9-5/8-in. enhanced single trip multi zone gravel pack system. This system appeared capable of providing significantly greater cost efficiency than conventional cased-hole stack-pack systems, which would make the marginal wells profitable. This paper describes the 3 wells completed by BSP in 2010 and 2011 using the enhanced single trip multi zone gravel pack system. For the 3 wells, a total of 10 zones required a sand control treatment. The paper also will describe why the enhanced single trip multi zone gravel pack system was chosen and will discuss the wellbore configuration, the implementation, and other field possibilities for the system. Finally, the paper will discuss the "best practices" learned from the first enhanced single trip multi zone gravel pack system installations; the challenges encountered during the job execution, and also, will compare the enhanced single trip multi zone gravel pack system with the conventional cased-hole stack-pack system to highlight the advantages of the new system.
- Asia > Indonesia > Sumatra > Aceh > North Sumatra Basin > B Block (0.99)
- Asia > Brunei > Bugan Field (0.99)
- Well Completion > Well Integrity > Zonal isolation (1.00)
- Well Completion > Sand Control > Sand/solids control (1.00)
- Well Completion > Sand Control > Gravel pack design & evaluation (1.00)
Pushing the Envelope of HT Drilling Fluids: Development and Field Applications of a Novel Non-Aqueous Drilling Fluid in the Gulf of Thailand
Charnvit, Kerati (M-I SWACO) | Kongto, Abhijart (M-I SWACO) | Huadi, Fransiskus (M-I SWACO) | Sharma, Sunil (M-I SWACO) | Simon, Gerard (CHEVRON) | Estes, Brent (CHEVRON) | Trotter, Neil (CHEVRON)
... Dial Reading 27 22 200-rpm Dial Reading 20 15 100-rpm Dial Reading 14 10 6-rpm Dial Reading 4 3 3-rpm Dial Reading 3 2 PV (cP) 18 13 YP (lb/100 ft 2 ) 9 9 10-Sec Gel Strength (lb/100 ft ...
...or NAF to perform within expectations, especially when coupled with acid gas contamination and high solids content, specifically low-gravity ...solids (LGS). Emulsifiers can thermally degrade leading to gelation problems as well as contributing to in...
...ameter Logging Success Wireline logging down to bottom Rheology 6 rpm within specification (8-12) Solids Content LGS within specification ( 5%) Filtration Control HTHP fluid loss within specification ( ...
Abstract Typical wells in the Gulf of Thailand are drilled using a slim-hole design that requires 6⅛-in. hole for their reservoir interval. The slim and highly deviated well geometry, potential of high acid gas contamination, and high-temperature environment requires a well-engineered non-aqueous drilling fluid (NAF) to meet the overall well objectives. These conditions always place severe limitations on the drilling fluids design and often lead to failures in openhole wireline logging operations, which is the most important well objective. The key fluid properties to ensure the success of wireline logging operations under this high temperature are high-temperature, high-pressure (HTHP) filtration control, filtercake quality, and thermal stability of the drilling fluid under extreme static condition. Selected emulsifier and HTHP filtration control agents work synergistically in providing excellent hole condition which allows the hole to be fully logged and evaluated. Clear benchmarks were set and monitored in all the field applications: (1) Successful wireline logging operation; (2) Variation of mud weight after static condition; (3) Variation of mud weight compared to formation tester data point. This paper details the design, development, and field applications of an ultra-high-temperature NAF used for drilling deep and hot wells in the Gulf of Thailand. In addition, the extensive laboratory work required to optimize the formulation for extreme high temperatures, the lessons learned, and the critical engineering guidelines for running a NAF in such harsh conditions will be described.
...0 Lime, gr 25.0 25.0 11.0 11.0 40.0 40.0 Barite, gr 245 245 633 633 204 204 Fatty Acid, vol % - - 4.3 - - ...3.45 - - 4.70 L. Phos., vol % - - 3.45 - - 4.10 - - 2.40 Urea, vol % - - 1.72 - - 2.00 -...
...n rate of the introduce into a marine environment. Their toxicity and contaminant fluid, and reduce solids handling and treatment biodegradation properties can vary widely. costs. The newly developed and op...
...is of the base fluid over time. The drill types of oil-based muds and cuttings, as the landers were solids contamination tests resulted in a relatively small change recovered and observations and measuremen...
Abstract Research has been conducted to reduce the environmental impact of drill cutting discharge, when using a synthetic, ester, or mineral oil based fluid. The successful application of this technology will increase the biodegradation rate of the contaminant fluid, and reduce solids handling and treatment costs. The newly developed and optimized process utilizes organic nitrogen and phosphorus compounds and fatty acids to enhance the biodegradation rate of waste fluid. Previous work discussed the chemistry and laboratory test protocol used to develop this approach. The design criteria demanded that the drilling fluid maintain stable fluid properties and resistance to common contaminants encountered while drilling. It was also important in the design work to insure the resultant fluid did not damage return permeability and maintained reservoir integrity. The final formulations also could not increase the toxicity of the drilling fluid, as determined by standardized test protocols. The final approach has resulted in a more readily biodegradable system than currently available synthetic-based fluids. Part two of this work demonstrated the effectiveness of the degradation booster fluid to increase aerobic and anaerobic biodegradation of several synthetic-base oils. Data collected from an isomerized olefin (IO) based biodegradation tests, Leptocheirus sediment toxicity and poly-nuclear aromatic hydrocarbons content clearly highlight the compliance of this novel invert fluid with regards to the Gulf of Mexico EPA protocol. This newly developed environmentally fluid can be applied not only offshore but in onshore sensitive areas. Introduction In the last decade new synthetic oils were introduced as base fluids for internal emulsion drilling fluids. These fluids demonstrate a low toxicity levels and good biodegradation rates. The use of these specially designed base oils allows the discharge of contaminated cuttings into the marine environment in many areas of the world. As the drilling and environmental community becomes more resolved to minimize the environmental impact of the drilling operation, the search for the maximum environmental friendly drilling fluid continues today. Initial work conducted by the authors indicated the rate of biodegradation of synthetic and mineral base fluids could be enhanced by chemical addition to the drilling fluid system. The approach discussed in this paper includes the use of biodegradation enhancement, while at the same time maintaining low toxicity values and excellent drilling fluid properties seen with the synthetic base oils. The chemical addition is referred to as "booster fluid" in this paper. The results of extensive laboratory testing confirmed the potential positive ecological impact of this novel drilling fluid. Mineral oil, linear alpha olefins (LAO), isomerized olefins (IO) and ester base fluids behave differently when introduce into a marine environment. Their toxicity and biodegradation properties can vary widely. When drill cutting are discharged into the marine environment any oily cuttings deposited on the seabed in large amounts will form cuttings piles and will soon exist under anaerobic conditions. This occurs because of the high organic load in which bacteria soon deplete the oxygen supply on the sea floor. The potential of large anaerobic cutting piles remains an important issue that concerns offshore drilling operations. In an effort to minimize the effect of cuttings piles on the environment, a method to speed the rate of aerobic and anaerobic biodegradation of synthetic drilling fluids was developed. The results and data collected in this study indicate the rate of both aerobic and anaerobic biodegradation of a synthetic drilling fluid can be accelerated by incorporating a treatment including the addition of a booster fluid.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Successful Implementation of Horizontal Open-Hole Gravel Packing in the Stybarrow Field Development, Offshore Western Australia
Napalowski, Ralf (BHP Billiton) | Hill, Robin Andrew (BHP Billiton Petroleum Americas Inc.) | Stomp, Robert John (BHP Billiton) | Derkach, Ed (M-I SWACO) | Fagervik, Egil Normann (Baker Hughes Malaysia Sdn. Bhd) | Manning, David Keith (VRMT Intl. Australia P/L.)
...re equivalent rates while pumping the planned sequence of optimized reservoir drilling fluid (RDF), solids-free fluid, brine and gravel carrier fluid including ceramic proppant material. Sedimentology and s...sign commenced with the selection of the most appropriate brine phase for reservoir drilling fluid, solids free displacement fluid and gravel pack carrier fluid. Borehole stability work initially predicted ... to be kept constant throughout the entire sandface completion operations, i.e. reservoir drilling, solids-free displacement, clear brine completion fluid, and gravel carrier fluids. The optimum brine phase...
...ration and production apparatus that allowed filtercake build-up with RDF, displacement of RDF with solids-free mud and gravel pack proppant placement under realistic downhole wellbore circulating condition...als, it was decided to displace the entire open-hole up to 200m into the 9.5/8" casing with sheared solids-free RDF. The following open-hole clean-up programme was implemented: 1. Drill to TD with 8.1/2" dr...illing BHA. 2. Clean out hole by sweeping drill cuttings and reducing solids content using 170 mesh or smallest shaker screens feasible to ensure continuous shaker operations. ...
...educe the dynamic filtercake. 6. Displace open-hole up to approx 200m inside the 9.5/8" casing with solids-free RDF. 7. POOH with drilling BHA. 8. RIH with clean-out BHA and clean-out 9.5/8" casing. 9. Pump...
Abstract Key sandface completion challenges were faced in the selection, design, planning and execution phases of the open-hole horizontal gravel pack completions in the deepwater Stybarrow Field, offshore Western Australia. Only limited technical experience and infrastructure were available in country to support such a complex operation. Additionally, the lateral reservoir quality variations and challenging sand/shale heterogeneities have necessitated an early focus on appropriate reservoir drilling fluid design, detailed sand screen selection, and gravel pack modeling to minimize premature screen out during gravel packing and ensuring minimal formation damage. This paper documents the multidisciplinary approach that commenced during the field appraisal and data acquisition stages to derive the sand management plan and culminated in the successful implementation of four horizontal open-hole gravel packs. A novel reservoir drilling fluid design, extensive formation damage testing and the selection of the circulating gravel packing technique have led to the successful sand control implementation with pack factors in excess of 100%. Attention to detail during detailed design, extensive contingency planning and diligent execution were major contributing factors in delivering high quality wells capable of producing as per basis of well design proven by early production performance. The Stybarrow Development represents the first successful implementation of horizontal open-hole gravel packing in Australia. Introduction The Stybarrow Field is a moderately sized biodegraded oil accumulation consisting of slope turbidite sandstones of the Macedon Formation in the Exmouth Sub-Basin offshore Western Australia. The reservoir comprises excellent quality, but poorly consolidated, sand rich turbidites (Ementon et al 2004). The Stybarrow Field is part of the Stybarrow Development which consists of the Stybarrow and Eskdale Fields. Both fields lie in >800m of water and constitute Australia's deepest water development, developed entirely by subsea wells connected to an FPSO. Critical to the development of both fields was the successful implementation of the sand management plan that predominantly relies on downhole sand exclusion installed in all development wells. The Stybarrow Field has been developed with four near horizontal open-hole gravel packed production wells in addition to three near vertical water injection wells completed with stand-alone screens. Voidage replacement via seawater injection, gradually supplemented with produced water, is required for pressure maintenance in the Stybarrow Field. Produced gas is re-injected into the gas cap of the nearby Eskdale Field, the oil leg of which is produced via a single horizontal well (Figure 1). Sand Management Data Acquisition Data acquisition for sand management and completion engineering purposes was identified early during the exploration and appraisal phases as a critical activity to derive an optimum sand management plan for the Stybarrow Development. Sand management was defined by a holistic approach to minimize the impact of sand production on facilities integrity and well performance in order to safeguard the production profile over the entire field life. During field appraisal it became evident that a key component of the overall sand management plan was to control sand production downhole. The data acquisition plan was consequently adjusted to obtain the appropriate data.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.69)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Deep Water Marine Environment (0.44)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-32-L > Stybarrow Field > Macedon Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-255-P > Stybarrow Field > Macedon Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > PL WA-36-R > Macedon Formation (0.99)
- (2 more...)
...90 22 90 60 60 Horizontal Length (ft) 0 0 2802 2438 3605 0 3135 0 0 No of Well Sections 3 1 4 4 4 3 4 3 3 Budget Days 19.3 10.7 37.5 30.4 33.7 19 34.1 23.7 23 Actual Days 13.7 10.7 47.2 37.7 18.3 8.9 29...nclination 90 45 51 90 47 50 51 39 Horizontal Length (ft) 3100 0 0 3302 0 0 0 0 No of Well Sections 4 3 3 4 3 3 3 3 Budget Days 33.4 19.8 20.7 33.5 19.1 21 19.1 21.5 Actual Days 25.9 24.1 14.6 27.7 13.7 14.8 1...
...of penetration (ROP) was 233 fph, including connection for logging. This logging pill has low drill solids, low time. During this interval, High Viscosity (Hi-Vis) Sweeps viscosity, high lime and required c...
...s needed to remove cuttings different from the first run. After analyzing the data from RSS beds. A solids free pill containing lubricant was spotted in the first run, it was suspected that excessive weight...
Abstract In October 2003, development drilling of the ConocoPhillips Indonesia Inc.Ltd operated Belanak Field commenced when the platform rig was rigged up over a previously installed twenty-four slot platform. Drilling commenced with the objective of drilling and completing ten slant directional wells and six horizontal wells. The objective of the Field development was to have high production rates available when the FPSO facilities arrived approximately twelve months later. Since the wells had to be pre-drilled before first production, it made sense to utilize a full batch drilling concept in order to minimize costs. The 13–3/8" surface casing strings were successfully batch set on all sixteen wells. This section was completed fifteen days ahead of budget time and set several world record penetration rates for a 16" tricone bits. The 9–7/8" hole/7–5/8" casing sections were batch set in ten wells. Most well objectives were met and the performance was exceptional in some wells, but, this section was plagued by surface and downhole equipment failures. The 12–1/4" hole/9–5/8" casing sections were batch set in six wells. All well objectives were met including landing all wells in the reservoir at 90o. Time to complete this section was longer than expected due to inconsistent BHA response. The 8–1/2" horizontal hole sections were then drilled and completed with a 3,500 ft average hole length for the same six wells. This paper will focus on the drilling operations and discuss the performance and problems encountered. The Belanak drilling team was committed to continuous improvement by capturing data and immediately implementing the learning's. This commitment to maximize the learning curve resulted in minimizing cost and a successful intensive batch drilling operation. Introduction The Belanak development project is the development of an offshore oil Field located in Block B area of the South Natuna sea. This Field is located approximately 100 km North of Matak Island in Indonesia or 253 miles NE of Singapore. Figure-1 shows the Belanak Field location. The Belanak Field was discovered in January 1975 when the Belanak-1 well was drilled. After the first well, another six appraisal wells were drilled in the field. The primary target reservoirs, in the initial phase of this development, are Gabus Massive and Gabus Zone-3 sandstones. These formations both have gas caps overlying oil legs, containing light oil (40- 45° API) with a high pour point (75°F) and low sulphur content. The development plan incorporates the use of horizontal wells to minimize gas coning in the Gabus Massive and conventional deviated wells to produce both oil and gas from Gabus Zone-3. It requires seventeen slant and nine horizontal wells in the main Belanak Field with the possibility of drilling up to eight further wells from either of the two wellhead Platforms (WHP-A and WHP-B). The first phase of the development program called for drilling ten slant wells and six horizontal wells from WHP-A. These wells were to be predrilled prior to the production facilities being installed. This would allow for the benefits and cost savings of "batch" drilling to be realized and to deliver sixteen wells at first production. Figure-2 shows the Belanak Field development plan schematic. On October 18, 2003, the platform rig was accepted by the operator on WHP A and batch drilling operations commenced. The emphasis of this paper will be the batch drilling operations which consisted of cleaning out conductors, drilling and casing the 16" surface and 9–7/8" production sections, landing horizontal wells in the 12–1/4" sections, then drilling and completing 8–1/2" lateral sections. Figure-3 shows typical wellbore schematic in the Belanak field.
Flow Instability in Deepwater Flowlines and Risers - A Case Study of Subsea Oil Production from Chinguetti Field, Mauritania
Takei, J.. (PETRONAS Carigali Sdn. Bhd.) | Zainal, M. Z. (PETRONAS Carigali Sdn. Bhd.) | Ramli, R.. (PETRONAS Carigali Sdn. Bhd.) | Matzain, B.. (SPT Group Pty Ltd.) | Myrland, F.. (SPT Group Pty Ltd.) | Shariff, A. M. (Universiti Teknologi Petronas)
...lity Index Stability Group 5 th April 09 3.9 Low Set 1 2.0 Med Set 2 2.5 Med Set 3 1.9 High Set 4 3.3 Low Set 5 1.4 High Set 6 - - Table 7: FL1 Slugging Characteristics Comparison Slug Frequency [1/h...
... tuning was not necessary and since production rates were relatively high, flow restrictions due to solids and sands were not expected during this period. The modeling approach for the wells was to use the ...or FL1 and FL2. It was postulated that the Chinguetti flowlines/risers could have been subjected to solids deposition due to low production during the April 2009 production period. If there were localized b...
Abstract The Chinguetti field located west of the Mauritania coastline has recently experienced a slugging condition in its flowline and riser systems. A study was undertaken in which integrated production system models of Chinguetti wells, flowlines and risers were developed using OLGA transient multiphase flow simulator. The field is at a water depth of ∼800m and was developed with subsea wells, manifolds, 2 flexible flowlines and lazy "S" shaped risers tied back to a permanently moored turret Floating Production Storage Offloading (FPSO) located 6km away from the furthest drill centre. The main objective of the study was to assess slugging and potential methods to improve flow stability in the Chinguetti systems. An extensive field validation and benchmarking exercise was performed by tuning the models to match field pressures and phase flowrates in the systems. The goal was to validate the models as closely imitating the conditions in the field. However, uncertainties in the field data made it difficult to reach satisfactory results in the benchmarking exercise. Simulations were then performed to examine the impact of various changes in operating conditions on flow instability. These included changes in well routings, gas lift injection rates and location of injection points, riser and wellhead choke openings. The degree of fluctuations in liquid arrival rates and the characteristics of liquid slugs (length and frequency) were used to categorize the severity of flow instabilities for a range of operating conditions. Results from field implementation of recommended changes in operating conditions indicated improvement in flow stability. The success of this study was found to be dependent not only upon the inputs and assumptions made in the production system models but also on the outcome of the field validation exercises, and the understanding of pertinent governing factors influencing slugging behavior. The study highlights the methodology and analysis used to assess flow instability, outcome of field implementation, challenges faced and solutions proposed to minimize the flow instability of a deepwater oil field development.
- North America > United States (0.94)
- Africa > Mauritania > North Atlantic Ocean (0.70)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- Africa > Mauritania > North Atlantic Ocean > Mauritania-Senegal-Guinea-Bissau Basin > PSC B > Block 4 > Chinguetti Field (0.99)
- Africa > Mauritania > North Atlantic Ocean > Mauritania-Senegal-Guinea-Bissau Basin > PSC A > PSC B > Block 4 > Banda Field (0.99)
- Africa > Mauritania > North Atlantic Ocean > Mauritania-Senegal-Guinea-Bissau Basin > PSC A > Block 4 > Block 4 > Banda Field (0.99)
- Production and Well Operations > Artificial Lift Systems > Gas lift (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Risers (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Pipeline transient behavior (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (1.00)
... Pressure (psi) B Sand Conc. (lb/gal) C C 10 5000 10 9 9 8 4000 8 7 7 6 3000 6 5 5 4 2000 4 3 3 2 1000 2 1 1 0 0 0 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 May/18/2001 May/18/20...
...ion to the repositioned inside the casing, and the BOP's are closed for filter cake material, drill solids also contribute and great effort the subsequent cleaning of the casing, BOP's, and riser. is placed...
Abstract Although extended reach and horizontal wells in deepwater fields have presented many difficult challenges, operators have been willing to accept the challenges because of the substantial net reserves that the deepwater fields offer. Unfortunately, although promising new technologies that target the more extreme conditions inherent to deepwater completions have been introduced, many operators have hesitated to try them because they lack proven track records. Fortunately, this has not been the case with one operator, and this paper will discuss the innovative technologies that were employed to successfully perform two "firsts" in gravel pack completions in complicated wellbore scenarios in a deepwater subsea field. The first job is the longest deepwater horizontal gravel pack (HZGP), run in Brazil. 75,000 pounds of gravel was placed in a 2,730-ft openhole section in 2,621 ft of water from the Ocean Alliance rig. The technologies that were instrumental in the success of this completion included special packer technology, a multi-position weight down tool with a HZGP pressure maintenance assembly, and a new type of sand control screen. Despite the long slant section (6560 ft @ 60 degrees) and openhole length, installation of the sand control completion was smooth, never reaching more than 10,000 pounds of drag. The second job used a realtime operations (RTO) data acquisition and visualization system during a gravel pack procedure. The system employs advances in traditional data management and networking to allow the personnel at the wellsite as well as all remotely stationed personnel to monitor critical well parameters so that immediate decisions on procedural changes can be made. The system allowed the service personnel and operator to monitor the job's execution and adjust pumping parameters as needed. This job illustrates the enhanced capabilities that can be gained from adapting innovative techniques to traditional procedures. The best practices from these completions will be used in all future jobs. This paper illustrates the importance and gains possible from considering new technologies and applying them where feasible. History of the Fields The deepwater subsea fields are approximately 100 miles east of Macae in Block BC-50B in Brazil's Campos Basin. Development of the two fields covers an area of 142 square miles that will be serviced by two floating production storing and offloading (FPSO) vessels that will receive production from 55 subsea wells. Water depths of the wells range from approximately 2800 to 3800 ft. Recoverable reserves for the first field are estimated to be at 867 million barrels of oil and 375 billion cubic feet of gas. The estimated reserves for the second field are 362 million barrels of oil and 141 billion cubic feet of gas. The location of the fields can be seen in the map in Fig. 1. The most prolific Brazilian turbidite reservoirs are included in the Upper Oligocene/Lower Miocene section. The oil is concentrated in seven oil fields. The first deepwater Campos Basin discoveries date back from the mid 1980's. Initially, the reservoirs were thought to be homogeneous, widespread turbidite fans, however, as more extensive production data and cores were provided, the picture changed. The reservoirs were actually very complex and heterogeneous (See Fig. 2). Gravel/sand-rich channel complexes occur in areas with slope oversteepening due to upward movement of underlying Aptian evaporates and intense faulting. Thus, sand control would have to be considered in development of the wells. Producing the fields is a massive undertaking and will add 30% to the current one million BOPD output from the area. The development project includes 55 wells of which 22 will be horizontal producers, 2 multilateral producers, 8 horizontal injectors, and 8 piggyback injectors. The 15 wells already in production will be recompleted.
- South America > Brazil (1.00)
- North America > United States (0.93)
- Phanerozoic > Cenozoic > Paleogene > Oligocene (0.54)
- Phanerozoic > Cenozoic > Neogene > Miocene (0.54)
- Information Technology > Communications > Networks (0.68)
- Information Technology > Architecture > Real Time Systems (0.48)
...uite limited. The relatively high (62) liquid superficial velocities necessary for the transport of solids demand gas velocities higher than 20 m/s for the 2 n occurrence of annular flow. In other words, ...
Abstract A mechanistic model is formulated to predict the mixture behavior for upward two-phase flow in concentric annulus. The model is composed of a procedure for flow pattern prediction and a set of independent mechanistic models for calculating gas fraction and pressure drop in bubble, dispersed bubble, slug and annular flow. In addition, some aspects of churn flow such as the slug/churn transition and the predictions of pressure drop are discussed. A comprehensive experimental program was also launched to collect data. An extensive full-scale investigation was executed in a 1278 m vertical well with an 88.9 mm×159.4 mm (3.5 in.×6.276 in.) annulus. The test matrix covered the whole range of possible combinations of liquid and gas injection rates for an UBD operation in a similar geometry. Small-scale tests were also performed in a U-tube, which simulates the simultaneous injection of liquid and gas through the drill string. The U-tube apparatus comprehended a descending pipe (ID=34 mm=1.34 in.) and a 41 mm×74 mm (1.61 in.×2.91 in.) ascending annulus. Small-scale data available in the literature were also collected and catalogued. The model is validated against the acquired database and shows a good performance for pressure drop prediction. Further, the performance of the model is also compared with other multiphase empirical or mechanistic models from the literature. The proposed model performs better than the other alternatives. Introduction Upward two-phase flow through an annular channel is encountered in various industrial applications such as heat exchangers, power plants and production of oil and gas. However, the intensity of engineering use does not reflect on the research efforts because literature presents a small number of related studies. In the past, the interest of the oil industry for this subject was restricted to some high productivity wells flowing through the casing-tubing annulus. In addition, some studies were motivated by oil wells lifted by sucker rod pumps. Recently, it is gaining more relevance as grows the popularity of the underbalanced drilling technology. Considering that accurate prediction of downhole pressure is a key factor for a successful UBD operation, the knowledge of the two-phase flow through annuli becomes more relevant. Because of the complex nature of the problem, most of the calculation approaches in current practice for UBD are based on empirical methods. As a result, the possibilities of use are restricted to specific conditions without well-defined borders. In this scenario, similarly to the trend observed in two-phase flow in pipes, the application of mechanistic models is supposed to be the natural way for improvement. The mechanistic or phenomenological approach postulates the existence of different flow configurations and formulates separated models for each one of these flow patterns to predict the main parameters as gas fraction, in-situ velocities and pressure drop. Since the basic laws of fluid mechanics are behind the development, the results can be extended to conditions different than those used for the development. Literature Review. Sadatomi et al. performed experiments in a 15 mm×30 mm (0.59 in.×1.18 in.) annulus and evaluated bubble rise velocities. They also utilized the Lockhart & Martinelli relationship for studying pressure drops. However, their investigation did not cover all flow configurations. Caetano developed a mechanistic model for dealing with vertical upward two-phase flow in concentric and eccentric annulus. He also performed an extensive experimental investigation in a 42.2 mm×72.6-mm (1.66 in.×3 in.) annular space using air-water and air-kerosene. Despite the comprehensiveness of his study, work is still needed for improvements. For instance, the sub-model for annular flow presented an overall tendency for overestimating total pressure gradients predictions 66% higher in average than the measured values for the air-kerosene mixture. Kellessidis and Dukler investigated the flow pattern map for upward two-phase flow. They also performed experimental tests in a 50.8 mm×76.2 mm (2 in.×3 in.) annular channel, although the study was limited to flow pattern definition. Literature Review. Sadatomi et al. performed experiments in a 15 mm×30 mm (0.59 in.×1.18 in.) annulus and evaluated bubble rise velocities. They also utilized the Lockhart & Martinelli relationship for studying pressure drops. However, their investigation did not cover all flow configurations. Caetano developed a mechanistic model for dealing with vertical upward two-phase flow in concentric and eccentric annulus. He also performed an extensive experimental investigation in a 42.2 mm×72.6-mm (1.66 in.×3 in.) annular space using air-water and air-kerosene. Despite the comprehensiveness of his study, work is still needed for improvements. For instance, the sub-model for annular flow presented an overall tendency for overestimating total pressure gradients predictions 66% higher in average than the measured values for the air-kerosene mixture. Kellessidis and Dukler investigated the flow pattern map for upward two-phase flow. They also performed experimental tests in a 50.8 mm×76.2 mm (2 in.×3 in.) annular channel, although the study was limited to flow pattern definition.
...it is an important tool for production engineers. Results of a trial example can be seen in Section 4. ...3.3 Description of the wax model used In this research, two new wax models were applied to the integrat...
Abstract There is a lack of comprehensive simulation tools that (a) accommodates the complexities of advanced completions together with near wellbore behaviour, and (b) has reliable wax precipitation models for production planning. In this work, these issues are tackled by combining three specific models. Firstly, a steady-state, three-phase, non-isothermal flow model in advanced horizontal completions was implemented to run fluid specific simulations, thereby calculating field specific flow conditions. This is useful in situations when fluid specific temperature calculations are important, such as wax crystallization. Secondly, a non-isothermal vertical flow model was developed by combining Hagedorn and Brown's multi-phase flow correlation with Ramey's multi-phase temperature model by solving them in sequence (iteratively). The advanced horizontal well model and vertical flow model were coupled iteratively at the bottom hole where the two models meet. Thirdly, two different analytical wax crystallization models were incorporated in the above coupled flow simulator to calculate the location of wax precipitation along the vertical section of the well. These three simulation models, individually and in combination, were tested and found to be in par with theory, expectations and published results. Additionally, significant difference was noted between Ramey's analytical temperature profile (which is a widely used approximation) and the complete Ramey's model integrated with the simulator developed in this work.
- Europe (0.93)
- North America > Canada (0.93)
- North America > United States > Texas (0.46)
- North America > United States > Louisiana (0.28)