The Use of New Technologies to Maximize Oil Production in a Viscous Oil Field in Arctic Environment: The Nikaitchuq Experience

2014 ◽  
Author(s):  
Stefano Raniolo ◽  
Silvia Mancini ◽  
Silvia Vimercati ◽  
Pablo Hugo Gentil ◽  
Davide Simeone ◽  
...  
Keyword(s):  
New Technologies ◽  
Oil Production ◽  
Oil Field ◽  
Arctic Environment ◽  
Viscous Oil

Leveraging a New Well Delivery Methodology for Stellar Drilling Results Steam Injection Project Case Study

2021 ◽  
Author(s):  
Carlos Alejandro Terrones Brand ◽  
Miguel Alejandro Basso Mora ◽  
Rajeswary Kandasamy ◽  
Sergio Comarin ◽  
Felipe Rene Bustos Guevara ◽  
...  
Keyword(s):  
Performance Monitoring ◽  
New Technologies ◽  
Service Providers ◽  
Oil Production ◽  
Steam Injection ◽  
Gas Production ◽  
Oil Field ◽  
Superior Performance ◽  
Stringent Performance

Abstract Mexico has set challenging oil and gas production to meet worldwide demand. In order to deliver promised oil production outputs in this challenging environment, the operator came up with efficient partnerships with key service providers to leverage resources and technical know-how whilst encouraging knowledge transfer and drilling project cost reduction. By working with various service companies, the operator creates a competitive environment where each strives to outperform the other. One such success case is in the "S" field, a heavy oil field producing via steam injection in the South of Mexico. Utilizing a creative design and execution methodology, the "S" project team succeeded to deliver improved project performance over the course of drilling the 14 wells in the campaign. The average well operational time was successfully reduced by 10%, hence maximizing the well construction index to 122 m/day and reducing overall well costs. The main strategy to optimize performance is to re-engineer solutions for profitability such as performing a study to replace OBM by WBM, designing a new wellhead system, collaborating with the rig contractor to reduce flat time activities, redesigning cement properties for losses mitigation, improvement of ROP by merging new technologies and local practices, among others. Complementary to this, the strategy is to prioritize realistic areas of improvement by the development and utilization of a new tool called Best of the Best (BoB), a methodology breaking down all well activities in order to measure its fastest time per well and then aiming to achieve that aggressive goal. Detailed follow up in the field allows to reduce operational times by allowing the wellsite team monitor and suggest new and improved ways of doing a routine task all of which result in lower costs per foot. Utilizing this BoB approach and stringent performance monitoring while drilling (pre-actual-post) activity analysis, allowed superior performance to be achieved. The project reached a 60% improvement on well times from the first well drilled to the best performing well. The best well was drilled in 8.68 days versus a field average of 18 days (217 m/day construction index). This generated 369,000 bbls of earlier oil production, 176 days ahead vs client expectations. Furthermore, in coordination with field staff, lessons learned were captured. But this is not enough since fast and effective communication is required, and the BoB methodology provides the solution to share optimization tricks quickly and effectively between crews, to continue well to well improvement and overall project and field level learning. Improved well delivery results is possible only by aligning the detailed planning and execution follow up in both the wellsite and a remote operations centre which monitored drilling activity in real time from town. This synergy and proactive communication system is also a key factor in the project delivery. This paper will present the results from the first application of the ‘Best of Best' (BoB) methodology in Mexico. This successful application enforces the idea that by coupling re-engineering practices to develop a more creative well design along with stringent performance monitoring; any field performance can be improved to deliver stellar results.

Selection of effective wax (deposition) inhibitors to oil production and transportation at the Kondinskoye oil field

2020 ◽  
pp. 120-127
Author(s):  
E. N. Skvortsova ◽  
O. P. Deryugina
Keyword(s):  
Laboratory Tests ◽  
Initial Dosage ◽  
Oil Production ◽  
Oil Field ◽  
Transport Systems ◽  
Asphaltene Precipitation ◽  
Wax Deposition ◽  
Selection Of ◽  
Pilot Tests

The article discusses the results of a study on the selection of wax inhibitors that can be used at the Kondinskoye oil field during transportation and dehydration of the emulsion.Asphaltene precipitation is one of the most serious issues in oil production. The experiment was conducted in order to select the most effective wax inhibitors. We have carried out laboratory tests to choose the most effective wax inhibitor in the conditions of oil production, collection, preparation and external transport systems at the Kondinskoye oil field. Based on the data obtained, wax inhibitor-2, wax inhibitor-4, and wax inhibitor-6 have shown the best results in ensuring the efficiency of inhibition, which should be at least 70 %, and, therefore, they can be allowed to pilot tests. The recommended initial dosage of inhibitors according to the results obtained during pilot tests should be at least 500 g/t of oil.

Study and Comparison of Vibration-Based Intrusive and Non-Intrusive Sand Monitoring System

2013 ◽  
Vol 701 ◽  
pp. 440-444
Author(s):  
Gang Liu ◽  
Peng Tao Liu ◽  
Bao Sheng He
Keyword(s):  
Real Time ◽  
Monitoring System ◽  
Oil Production ◽  
Oil Wells ◽  
Oil Field ◽  
Sand Production ◽  
The Status

Sand production is a serious problem during the exploitation of oil wells, and people put forward the concept of limited sand to alleviate this problem. Oil production with limited sanding is an efficient mod of production. In order to complete limited sand exploitation, improve the productivity of oil wells, a real-time sand monitoring system is needed to monitor the status of wells production. Besides acoustic sand monitoring and erosion-based sand monitoring, a vibration-based sand monitoring system with two installing styles is proposed recently. The paper points out the relationships between sand monitoring signals collected under intrusive and non-intrusive installing styles and sanding parameters, which lays a good foundation for further study and actual sand monitoring in oil field.

Increasing Wells Lifetime by Using PAR VALVE to Overcome Sand Settling Problems at Pertamina EP Asset 1 Field Jambi

2021 ◽  
Author(s):  
A. S. Ramadhan
Keyword(s):  
Oil Production ◽  
Oil Field ◽  
Average Lifetime ◽  
Sand Production ◽  
Maintenance And Repair ◽  
Engine Maintenance

In the Jambi oil field, sand production can create unattainable production targets and short-lived well lifetime. One function of the Jambi Engineering and Planning Field is to look for solutions to these problems, such as the installation of progressive cavity pumps (PCP) into wells. Although successful, a problem that often arises in PCP wells is sand settling when the PCP is off, for example during electric trips, engine maintenance and repair of flowlines. This settling can lead to a stuck PCP. A recent solution has been to install a Pressure Actuated Relief (PAR) valve, where the tool directs sand deposits out of the tubing to the annulus so that it does not enter the pump. Installation of this tool has increased the average lifetime of sandy wells from 2 months to 6 months, and has increased oil production in these wells by up to 47%.This paper will discuss the successful installation of a PAR Valve into well KTT-08 in the Jambi Field.

Unlocking By-Passed Oil with Autonomous Inflow Control Devices Through an Integrated Approach

2021 ◽  
Author(s):  
Pawan Agrawal ◽  
Sharifa Yousif ◽  
Ahmed Shokry ◽  
Talha Saqib ◽  
Osama Keshtta ◽  
...  
Keyword(s):  
Continuous Production ◽  
Oil Production ◽  
Gas Production ◽  
Oil Field ◽  
Production Performance ◽  
Fluid Distribution ◽  
Flow Profile ◽  
Horizontal Drain ◽  
Control Devices

Abstract In a giant offshore UAE carbonate oil field, challenges related to advanced maturity, presence of a huge gas-cap and reservoir heterogeneities have impacted production performance. More than 30% of oil producers are closed due to gas front advance and this percentage is increasing with time. The viability of future developments is highly impacted by lower completion design and ways to limit gas breakthrough. Autonomous inflow-control devices (AICD's) are seen as a viable lower completion method to mitigate gas production while allowing oil production, but their effect on pressure drawdown must be carefully accounted for, in a context of particularly high export pressure. A first AICD completion was tested in 2020, after a careful selection amongst high-GOR wells and a diagnosis of underlying gas production mechanisms. The selected pilot is an open-hole horizontal drain closed due to high GOR. Its production profile was investigated through a baseline production log. Several AICD designs were simulated using a nodal analysis model to account for the export pressure. Reservoir simulation was used to evaluate the long-term performance of short-listed scenarios. The integrated process involved all disciplines, from geology, reservoir engineering, petrophysics, to petroleum and completion engineering. In the finally selected design, only the high-permeability heel part of the horizontal drain was covered by AICDs, whereas the rest was completed with pre-perforated liner intervals, separated with swell packers. It was considered that a balance between gas isolation and pressure draw-down reduction had to be found to ensure production viability for such pilot evaluation. Subsequent to the re-completion, the well could be produced at low GOR, and a second production log confirmed the effectiveness of AICDs in isolating free gas production, while enhancing healthy oil production from the deeper part of the drain. Continuous production monitoring, and other flow profile surveys, will complete the evaluation of AICD effectiveness and its adaptability to evolving pressure and fluid distribution within the reservoir. Several lessons will be learnt from this first AICD pilot, particularly related to the criticality of fully integrated subsurface understanding, evaluation, and completion design studies. The use of AICD technology appears promising for retrofit solutions in high-GOR inactive strings, prolonging well life and increasing reserves. Regarding newly drilled wells, dedicated efforts are underway to associate this technology with enhanced reservoir evaluation methods, allowing to directly design the lower completion based on diagnosed reservoir heterogeneities. Reduced export pressure and artificial lift will feature in future field development phases, and offer the flexibility to extend the use of AICD's. The current technology evaluation phases are however crucial in the definition of such technology deployments and the confirmation of their long-term viability.

Unlocking Idle Production in an Offshore Sandstone Oil Field With Gas Hydrate Issues

2021 ◽  
Author(s):  
Babalola Daramola
Keyword(s):  
Gas Hydrate ◽  
Oil Production ◽  
Oil Field ◽  
Third Party ◽  
Flow Assurance ◽  
Well Testing ◽  
Production Wells ◽  
Oil Flow ◽  
Offshore Oil ◽  
Production Losses

Abstract This publication presents how an oil asset unlocked idle production after numerous production upsets and a gas hydrate blockage. It also uses economics to justify facilities enhancement projects for flow assurance. Field F is an offshore oil field with eight subsea wells tied back to a third party FPSO vessel. Field F was shut down for turnaround maintenance in 2015. After the field was brought back online, one of the production wells (F5) failed to flow. An evaluation of the reservoir, well, and facilities data suggested that there was a gas hydrate blockage in the subsea pipeline between the well head and the FPSO vessel. A subsea intervention vessel was then hired to execute a pipeline clean-out operation, which removed the gas hydrate, and restored F5 well oil production. To minimise oil production losses due to flow assurance issues, the asset team evaluated the viability of installing a test pipeline and a second methanol umbilical as facilities enhancement projects. The pipeline clean-out operation delivered 5400 barrels of oil per day production to the asset. The feasibility study suggested that installing a second methanol umbilical and a test pipeline are economically attractive. It is recommended that the new methanol umbilical is installed to guarantee oil flow from F5 and future infill production wells. The test pipeline can be used to clean up new wells, to induce low pressure wells, and for well testing, well sampling, water salinity evaluation, tracer evaluation, and production optimisation. This paper presents production upset diagnosis and remediation steps actioned in a producing oil field, and aids the justification of methanol umbilical capacity upgrade and test pipeline installations as facilities enhancement projects. It also indicates that gas hydrate blockage can be prevented by providing adequate methanol umbilical capacity for timely dosing of oil production wells.

Review of Practical Experience by Polymer Flooding at Daqing

2009 ◽  
Vol 12 (03) ◽  
pp. 470-476 ◽  
Author(s):  
Dongmei Wang ◽  
Huanzhong Dong ◽  
Changsen Lv ◽  
Xiaofei Fu ◽  
Jun Nie
Keyword(s):  
Oil Production ◽  
Polymer Flooding ◽  
Oil Field ◽  
High Permeability ◽  
Sweep Efficiency ◽  
Molecular Weights ◽  
Well Spacing ◽  
Polymer Flood ◽  
Daqing Oil Field ◽  
Water Cut

Summary This paper describes successful practices applied during polymer flooding at Daqing that will be of considerable value to future chemical floods, both in China and elsewhere. On the basis of laboratory findings, new concepts have been developed that expand conventional ideas concerning favorable conditions for mobility improvement by polymer flooding. Particular advances integrate reservoir-engineering approaches and technology that is basic for successful application of polymer flooding. These include the following:Proper consideration must be given to the permeability contrast among the oil zones and to interwell continuity, involving the optimum combination of oil strata during flooding and well-pattern design, respectively;Higher polymer molecular weights, a broader range of polymer molecular weights, and higher polymer concentrations are desirable in the injected slugs;The entire polymer-flooding process should be characterized in five stages--with its dynamic behavior distinguished by water-cut changes; -Additional techniques should be considered, such as dynamic monitoring using well logging, well testing, and tracers; effective techniques are also needed for surface mixing, injection facilities, oil production, and produced-water treatment; andContinuous innovation must be a priority during polymer flooding. Introduction China's Daqing oil field entered its ultrahigh-water-cut period after 30 years of exploitation. Just before large-scale polymer-flooding application, the average water-cut was more than 90%. The Daqing oil-field is a large river-delta/lacustrine facies, multilayered with complex geologic conditions and heterogeneous sandstone in an inland basin. After 30 years of waterflooding, many channels and high-permeability streaks were identified in this oil field (Wang and Qian 2002). Laboratory research began in the 1960s, investigating the potential of enhanced-oil-recovery (EOR) processes in the Daqing oil field. After a single-injector polymer flood with a small well spacing of 75 m in 1972, polymer flooding was set on pilot test. During the late 1980s, a pilot project in central Daqing was expanded to a multiwell pattern with larger well spacing. Favorable results from these tests--along with extensive research and engineering from the mid-1980s through the 1990s--confirmed that polymer flooding was the preferred method to improve areal- and vertical-sweep efficiency at Daqing and to provide mobility control (Wang et al. 2002, Wang and Liu 2004). Consequently, the world's largest polymer flood was implemented at Daqing, beginning in 1996. By 2007, 22.3% of total production from the Daqing oil field was attributed to polymer flooding. Polymer flooding boosted the ultimate recovery for the field to more than 50% of original oil in place (OOIP)--10 to 12% OOIP more than from waterflooding. At the end of 2007, oil production from polymer flooding at the Daqing oil field was more than 10 million tons (73 million bbl) per year (sustained for 6 years). The focus of this paper is on polymer flooding, in which sweep efficiency is improved by reducing the water/oil mobility ratio in the reservoir. This paper is not concerned with the use of chemical gel treatments, which attempt to block water flow through fractures and high-permeability strata. Applications of chemical gel treatments in China have been covered elsewhere (Liu et al. 2006).

Production Enhancement In Arctic Environment: The Multilateral Experience For Viscous Oil

2014 ◽  
Author(s):  
Stefano Raniolo ◽  
Silvia Mancini ◽  
Fausto Brega ◽  
Marco Rovellini ◽  
Pablo Hugo Gentil ◽  
...  
Keyword(s):  
Arctic Environment ◽  
Viscous Oil
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