The deposition of carbonate and sulphate scales is a major problem during oil and gas production. Managing scale with chemical application methods involving either scale prevention and/or removal are the preferred methods of maintaining well production. However, chemical scale control is not always an option, depending upon the nature of the reservoir and well completion and, in cases of severe scaling, the problem can render chemical treatments uneconomic unless other non-chemical methods are utilised.
A variety of non-chemical scale control methods exist, the most common being injection of low salinity brines or low sulphate seawater (LSSW) using reverse osmosis and a sulphate removal plant (SRP) respectively. In addition, careful mixing of lift gas, produced waters and reinjection, coatings, smart well completions with active inflow control devices (ICD) and sliding sleeves (SS) are other methods.
All of these techniques, including combinations thereof, are currently in use and the advantages and disadvantages of the key techniques are compared to chemical methods for both carbonate and sulphate scale control. A detailed example from a North Sea field demonstrates where downhole chemical scale control has not been required through a strategy of careful mixing of lift gas, brines and produced water re-injection. This was combined with understanding fluid flow paths in the reservoir and their likely breakthrough at production wells.
Consideration is given to the injection of smart brines to scale deep in the reservoir, and data from North Sea chalk fields shows how "
This paper presents a comprehensive review of non-chemical methods for downhole scale control and discusses how the use of these techniques can provide alternative scale management strategies through minimising or alleviating the need for downhole chemical treatments.
Hu, Yisheng (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Mackay, Eric (Heriot-Watt University) | Vazquez, Oscar (Heriot Watt University ) | Ishkov, Oleg (Heriot-Watt University)
In waterflooded reservoirs under active scale management, produced-water samples are routinely collected and analyzed, yielding information on the evolving variations in chemical composition. These produced-water chemical-composition data contain clues as to the fluid/fluid and fluid/rock interactions occurring in the subsurface, and are used to inform scale-management programs designed to minimize damage and enable improved recovery.
In this interdisciplinary paper, the analyses of produced-water compositional data from the Miller Field are presented to investigate possible geochemical reactions taking place within the reservoir. The 1D and 2D theoretical model has been developed to test the modeling of barium sulfate precipitation implemented in the streamline simulator FrontSim. A completely 3D streamline simulation study for the Miller Field is presented to evaluate brine flow and mixing processes occurring in the reservoir by use of an available history-matched streamline reservoir-simulation model integrated with produced-water chemical data. Conservative natural tracers were added to the modeled injection water (IW), and then the displacement of IW and the behaviors of the produced water in two given production wells were studied further. In addition, the connectivity between producers and injectors was investigated on the basis of the comparison of production behavior calculated by the reservoir model with produced-water chemical data. Finally, a simplified model of barite-scale precipitation was included in the streamline simulation, and the calculation results with and without considering barite precipitation were compared with the observed produced-water chemical data. The streamline simulation model assumes scale deposition is possible everywhere in the formation, whereas, in reality, the near-production-well zones were generally protected by squeezed scale inhibitor, and, thus, the discrepancies between modeled and observed barium concentrations at these two given wells diagnose the effectiveness of the chemical treatments to prevent scale formation.
A technical-economic research was done evaluating microfiltration polymeric membranes and cartridge filters as pretreatment of Sulfate Removal Units (SRU). These units were installed in a Stationary Production Unit (SPU) to reduce the concentration of sulfate from seawater (injection water in Enhanced Oil Recovery). The use of seawater with low sulfate in enhanced oil recovery reduces the risk of sulfate deposits during the oil production. Ten companies from different nationalities involved in the industrial water treatment and manufacturing of polymeric membranes sector, have contributed to this comparative research (only a preliminary stage of the future study with qualitative and quantitative analyses). This paper shows that polymeric microfiltration is more advantageous because reduce operational costs and microbiological contamination resulting in a lower risk of biofouling. It also improves the quality of treated water, increases the operational stability and availability of the injection water, extending the lifetime of the nanofiltration polymeric membranes.
Davison, J. M. (Shell Global Solutions International B.V.) | Salehabadi, M. (Shell UK Exploration & Production) | De Gennaro, S. (Shell UK Exploration & Production) | Wilkinson, D. (Shell UK Exploration & Production) | Hogg, H. (Shell UK Exploration & Production) | Hunter, C. (Shell UK Exploration & Production) | Schutjens, P. (Shell Global Solutions International B.V.)
ABSTRACT: At the end of field life, wells require permanent plugging and abandonment (P&A) as part of decommissioning activities. Some UK fields developed in the 1970’s are reaching their end of field life, with UK industry estimates predicting well P&A costs over the next 30-40 years of 24 billion dollars. As well as the high financial cost, there is a significant HSSE exposure to ensure safe and reliable P&A such that no escape of hydrocarbons is possible to the near surface environment.
This paper discusses the role Geomechanics has to play in potentially reducing well P&A costs, but also ensuring integrity of the wells and formations over long time scales. Recent experience in the UK North Sea has highlighted the requirement for detailed geomechanical knowledge of the field. We will focus on three key areas for geomechanical analysis. Firstly, we discuss reservoir pressure re-charge and in-situ stress response, from simple pressure-depth plots to more complex 3-D numerical modelling of the stress changes in reservoirs and surrounding formations. An added level of complexity compared to ‘conventional’ geomechanical modelling is the ability to forward predict the reservoir pressure recharge over hundreds of years and the commensurate response of the in-situ stresses. Secondly, as well as the modelling of stress changes over time, Geomechanics has a key role to play in determining the opportunity of using shale creep deformation to create annular barriers in the place of cement. Lastly, in some cases the preferred P&A design for a well is not possible due to well access issues which then requires cross-flow analysis linked with the geomechanical response of permeable formations. This approach is required for containment risk assessment and application of ‘as low as reasonably practicable’ (ALARP) assessments for well and formation integrity. Each of these subjects will be covered with field examples from the UK North Sea which demonstrate the Geomechanical workflows employed and the impact these have had on the business.
The purpose of this paper is to increase the data in circulation regarding the value of well testing on established fields. The results of five phases of optimisation, resulting in a 17% increase in field production, following the change out of the multiphase flow meter (MPFM) are presented.
Background on the West Brae field and the uses of the original MPFM will be discussed. The challenges of monitoring and optimising a subsea field without any measurement at a well level, and the benefits associated with well testing are presented. The five phases used to optimise this six producer well system are detailed, along with the economic benefits seen. These economic benefits are compared to the economic case used to justify the replacement of the original MPFM.
Recognising the importance of good well integrity management practices, Marathon Oil UK developed an online database in conjunction with Expro to capture their well integrity data. The database has become a focal point to help facilitate Marathon's well integrity management processes and philosophies. The aim of this paper is to provide an overview of the rational for developing the system and the benefits that are being realised for both the Brae and Alvheim assets.
Lagler, Thomas (Dubai Petroleum Co.) | Al Haj, Mouad (MI Drilling Fluids) | Iskander, Gamal Ramses (M-I SWACO) | Rhodes, Jonathan Charles (INTEQ) | Al Kholy, Wael (Baker Hughes INTEQ) | Drumm, Niall James (INTEQ)
Offshore Dubai is a maturing oil province and to access outlying, isolated hydrocarbon reserves it is necessary to expose several unstable sections of troublesome shale during drilling operations. Historically during the drilling of these wells, wellbore time-based instability issues have been experienced in the Aruma and Laffan shales on offset wells with shorter buildup sections. It is therefore necessary to drill these sections as efficiently as possible, minimizing the time these shales are exposed.
Dubai Petroleum looked at a combination of new technologies available in the market that could help both to optimize the drilling of these sections and to meet the directional objectives. To control the shales a high-performance water-based mud (HPWBM) system with triple inhibition was proposed to Dubai Petroleum after a series of tests and field experience in the region.
To achieve the directional objectives and minimize the time to drill the section, a performance drilling system (rotary steerable tool in combination with a modular motor) and drilling dynamics sub were suggested. The section was drilled safely in a single run with all drilling objectives achieved and breaking all previous 24-hr ROP drilling records for an offshore Dubai Petroleum well. No shale instability issues were experienced, including the longest Aruma shale section ever drilled by Dubai Petroleum.
The combination of new technologies and detailed planning applied offshore Dubai for the first time allowed a step change in the Dubai Petroleum offshore drilling and enable previously inaccessible hydrocarbon reserves to be reached and produced.
This paper provides a summary and a guide of the enhanced-oil-recovery (EOR) technologies initiated in the North Sea in the period from 1975 until beginning of 2005. The five EOR technologies that have been initiated in this region are hydrocarbon (HC) miscible gas injection, water-alternating-gas (WAG) injection injection, simultaneous water-and-gas (SWAG) injection, foam-assisted WAG (FAWAG) injection, and microbial EOR (MEOR). Each EOR technology that has been initiated in the North Sea was identified with its respective maturity level and/or maturation time frame, technology use restrictions, and process efficiency on the basis of incremental oil.
Apart from WAG at Ekofisk and FAWAG at Snorre central fault block (CFB), all technologies have been applied successfully (i.e., positive in economic terms) to the associated fields. HC miscible gas injection and WAG injection can be considered mature technologies in the North Sea. The most commonly used EOR technology in the North Sea has been WAG, and it is recognized as the most successful EOR technology.
The main problems experienced were injectivity (WAG, SWAG, and FAWAG projects), injection system monitoring, and reservoir heterogeneities (HC miscible gas injection, WAG, SWAG, and FAWAG projects). Approximately 63% of all the reported EOR field applications have been initiated on the Norwegian continental shelf (NCS), 32% on the UK continental shelf, and the remainder on the Danish continental shelf. Statoil has been the leader in conducting EOR field applications in the North Sea. The majority of future research will concentrate on microbial processes, CO2 injection, and WAG (including SWAG) injection schemes.
In this review, laboratory techniques, global statistics, simulation tools, and economical evaluation were not considered and are considered outside of the scope of this paper.
In the North Sea, current average recovery factors (Hughes 2004; Xia 2004; Hansen and Westvik 2000; Blaker et al. 2006) are above 40%. As of 2003, the estimated oil reserves (OG21 2006) on the NCS are approximately 3850 million sm3, translating to an average recovery factor of 45% as shown in Fig. 1. The Ministry of Petroleum and Energy of Norway established the OG21 Task Force in 2001 to address the challenge of targeting a 50% average oil recovery factor set by the Norwegian Petroleum Directorate (NPD). This will yield 600 million sm3 additional oil. Among other technologies, EOR is one of the solutions to meet this goal.
Since 1982, several major Norwegian increased-oil-recovery (IOR) programs (Hinderaker et al. 1996), as listed in Table 1, have been initiated for additional oil recovery. Approximately 50 million USD has been invested in these Norwegian research programs (1982-1995). In 2003, the Oil and Gas in the 21st Century (OG21 Task Force) identified nine technology target areas to obtain the average recovery factors of 50% for oil and 75% for gas on the NCS (Blaker et al. 2006). On the basis of the IOR potential for each method and an evaluation of the importance and complexity of the technology gap, they proposed the following ranking of the different recovery methods:
Priority 1: (a) HC gas injection, WAG/SWAG, and FAWAG; (b) CO2 flooding; and (c) MIOR.
Priority 2: (a) waterflooding; (b) massive depressurization; and (c) air injection.
Priority 3: (a) gas condensate; (b) water additives; and (c) N2 and flue-gas injection.
Apart from these research programs, it is important to review the EOR technologies that have been initiated in the North Sea. The application of EOR technologies in the North Sea environment is more complex than, and quite different from, onshore applications. Thus, it is necessary to identify the applied EOR technologies in the North Sea with their respective maturity level, technology use restrictions, and process efficiency on the basis of incremental oil. The main objectives of this survey are to categorize the different EOR technologies initiated in the North Sea with respect to their respective maturity level to recognize important EOR related data such as reservoir fluid, formation properties, injection parameters, and enhanced production. In addition, we attempt to identify the EOR frontrunner in the North Sea by method, technology, location and company, lessons learned/key issues regarding EOR processes in the North Sea, and the EOR trend in the North Sea.
We would also like to emphasize that this review is based purely upon open literature and, therefore, may lack some important data that are not accessible through this source. This review should be considered as a guide for the EOR technologies initiated in the North Sea.