Some of the first high-pressure/high-temperature (HP/HT) development wells from Elgin and Franklin have been exposed to sustained casing pressures in their "A" annulus, threatening the integrity of the wells. The sustained pressure in the annulus was attributed to ingress through the production casing of fluids from the overburden chalk formations of the Late Cretaceous. The mechanism triggering the ingress into the "A" annulus was uncertain until access to the production casing was achieved. A recent campaign to abandon development wells of Elgin and Franklin that had sustained "A"-annulus pressure brings new evidence on the mechanism causing the ingress. Temperature surveys have been acquired in the production tubing to identify the fluid-entry points in the production casing. Multifinger calipers have been run in the production casing, revealing several shear-deformation features. These deformations are localized along various interfaces, and are attributed to the stress reorganization associated with the strong reservoir depletion. A detailed analysis of the surveys shows that fluid ingress is occurring at distorted casing connections, if located close to weak interfaces along which shear slip occurs. The shear deformation is suspected to cause a loss of the sealing capacity of the connection, leading to gas ingress into the "A" annulus. This conclusion emphasizes the need to consider any potential for localized shear deformations in designing casing for HP/HT wells.
Deep HPHT gas/condensate wells drilled and completed in open hole with cesium formate fluids clean-up naturally over hours and sometime days after initial production start-up as the wells unload water-based fluids and filter-cake from the reservoir zone. Following natural flowing clean-up during the start-up phase the wells tend to be highly productive, with low skins, and over the long-term those fields developed entirely and solely with cesium formate fluids have a reputation for delivering the recoverable hydrocarbon reserves projected in the operators' original business plans.
Laboratory core flooding tests with cesium formate fluids attempt to simulate real well clean-ups by applying drawdown pressures across the cores to create a cleansing flow of gas or oil to bring the rock permeability back to original native levels. Such attempts are usually successful in cores flooded with clear cesium formate brines, but it is rare to hear of cores that have cleaned up 100% after long duration exposure to cesium formate drilling fluids without subsequent mild stimulation with water or dilute acid. The persistent lack of congruence between observed well clean up performance and core flooding test results with cesium formate drilling fluids suggests that the attempted laboratory simulations of natural well clean up under drawdown might be inadequate or flawed in some way. One point of concern thought worthy of further investigation has been the duration of the drawdown-induced gas or oil flows applied in laboratory core flood tests to restore permeability. Wells have the opportunity to gradually clean up over years during production while laboratory clean ups by drawdown may only be applied for minutes or hours.
The objective of the study described in this paper was to review old core flood test data to see how quickly the simulated well clean-up procedures restored original permeability in tight gas-bearing sandstone cores after exposure to high-density cesium formate fluids for at least 48 hours under HPHT conditions.
Plugs of gas-bearing low permeability (2-20 mD) sandstone containing simulated formation water at irreducible water saturation were exposed to overbalanced cesium formate fluids for 48-96 hours under HPHT reservoir conditions. The plugs were then subjected to drawdown regimes with nitrogen gas, under HPHT reservoir conditions, to simulate formation and filter-cake clean-up of an open-hole deep gas well completion at production start-up. Fluid and gas flow rates, and differential pressures across the plug, were logged whenever flow was induced through the plug, to allow estimation of the relative permeability changes in the rock throughout the test sequence.
Results were compared for HPHT core flooding tests with: 10 pore volumes of SG 2.20 cesium formate completion brine pushed through 2 mD sandstone plugs at 200° C and high pressure, followed by a 48-hour static soak period under the same conditions. 10 pore volumes of SG 2.20 cesium formate completion brine pushed through 20 mD sandstone plugs at 175°C, followed by a 48-hour static soak period under the same conditions. SG 1.76 potassium/cesium formate drilling fluid circulated at 500 psi overbalance for 48 hours across the face of a 20 mD sandstone plug at 150°C, and then left static for a further 48 hours, resulting in 1.2 pore volumes of fluid loss through the core.
10 pore volumes of SG 2.20 cesium formate completion brine pushed through 2 mD sandstone plugs at 200° C and high pressure, followed by a 48-hour static soak period under the same conditions.
10 pore volumes of SG 2.20 cesium formate completion brine pushed through 20 mD sandstone plugs at 175°C, followed by a 48-hour static soak period under the same conditions.
SG 1.76 potassium/cesium formate drilling fluid circulated at 500 psi overbalance for 48 hours across the face of a 20 mD sandstone plug at 150°C, and then left static for a further 48 hours, resulting in 1.2 pore volumes of fluid loss through the core.
The straight cesium formate brines were removed quite promptly, typically within 15-30 minutes, from the 2-20 mD rock cores during drawdown. In the test with 20 mD sandstone plug and cesium formate drilling fluid the drawdown pressures were ramped up in stages from 1 psi to 100 psi during the clean-up phase but the rock plug was slower to regain its permeability. After 96 minutes of drawdown the plug had only recovered 79% of its initial relative gas permeability and clearly it was still in the process of cleaning up.
The test results provide new information about the clean-up rate of low permeability rock cores invaded by heavy cesium formate fluids under HPHT conditions and subjected to drawdown with gas.
The uncertainties of overpressure estimation are among the major challenges to the development of deep and hot reservoirs in many sedimentary basins especially with regards to drilling safety and well economics. However, because of the anticipated huge economic benefits of HPHT geological environments, stakeholders in the oil and gas industry consistently seek to have a good understanding of subsurface pressure systems in order to promote safe and sustainable investments therein. Accordingly, information is required to improve the regional knowledge of geopressures and for the calibration of functions aimed at optimising pre-drill pore pressure estimates for future wells. The Central North Sea, with its vast number of HPHT wells, pressure data, drilling information and documented operational experiences in exploration, drilling, development and production activities stands in a good stead as a "geopressure laboratory" for the fine-tuning of pore pressure prediction concepts, improvement of current geopressure practices and ultimately guide investment and operational decisions in the unexplored areas of the basin itself and elsewhere as geological realities could permit. For this reason, this study utilised downhole pressure-related data and wireline logs to evaluate the pressure regimes in the Central North Sea. The approach involved the quantification of overpressures using standard pore pressure prediction methods that make use of the density and velocity logs of mudstones. The results show that the estimated pore pressure profiles are consistent with measured pressure data in the Cenozoic formations, which makes it reasonable to assume that disequilibrium compaction is the cause of overpressure in this shallow section of the wells. Going deeper into the wells, within the sub-Chalk section, typical calibration parameters from log data could not be used to achieve reliable estimates of overpressures as was the case in the Cenozoic section. Remarkably, while it is possible to adjust the Eaton exponents in order to match estimates with measured data, a wide range of exponent values of between 4.0 and 7.0 is however required. The implication is that there is no systematic variation of the Eaton exponents with the amount of overpressure or depth of burial of the sub-Chalk strata.
De Gennaro, S. (Shell U.K. Limited) | Taylor, B. (Shell U.K. Limited) | Bevaart, M. (Shell U.K. Limited) | van Bergen, P. (Shell U.K. Limited) | Harris, T. (Shell U.K. Limited) | Jones, D. (Shell U.K. Limited) | Hodzic, M. (Shell U.K. Limited) | Watson, J. (Shell U.K. Limited)
ABSTRACT: The Shearwater field located in the UK Central Graben represents one of the most challenging high-pressure, high-temperature (HP/HT) developments of its kind in the North Sea. During production, the strong depletion of the Fulmar reservoir caused a number of geomechanical-related problems, including the failure of the initial development wells, and consequently, loss of production. In order to reinstate production at Shearwater, five infill wells have been drilled and completed successfully. This success was largely attributed to a multidisciplinary effort to understand the post-production changes of the overburden. In this paper, a comprehensive 3D geomechanical model is presented that was used as a key design foundation for safe HP/HT well delivery. The model results and interpretations are discussed, and a summary of the current understanding of the evolution of the overburden from a geomechanical perspective is provided. The challenges associated with infill drilling and, in particular, the loss of fracture gradient and the closure of the drilling mud weight window between this and pore pressure, and how these have added complexity to the drilling practices are described. Finally, key technologies implemented to overcome these issues including Managed Pressure Drilling, Drill-In Liner and Wellbore Strengthening are discussed.
The Shearwater field located in the UK Central Graben represents one of the most challenging high-pressure, high-temperature (HP/HT) developments of its kind in the North Sea. At the time of the initial development, elevated pressures in excess of 15,000 psi and temperatures greater than 350°F, and structural geology complexity, posed major technical challenges to Shearwater. These challenges involved all aspects of well construction and production in HP/HT conditions. Despite the challenges, all initial development wells were drilled successfully.
During the first years of production, and similar to other HP fields, reservoir pressures dropped rapidly to 8,000 psi on average. The strong depletion of the reservoir, in combination with the high compressibility of the reservoir rock, resulted in compaction of the Fulmar sandstones and led to displacements, deformations and stress changes in the overburden rock. Compaction-induced stress changes in the overburden (“stress arching”) were the driving force for a number of geomechanical-related subsurface problems. During 2004-2007, it resulted in four production liners being sheared due to slippage along faults or bedding planes near the crest of the structure. Furthermore, over time, some initial development wells then experienced rapid A-annulus pressure increases, suggesting a leak of the production casing at Hod Chalk Formation level.
This paper looks, rather uniquely, at an HPHT field in the UK Sector of the North Sea which was designed and developed during the mid 1990's and which, relatively recently, gave problems due to a gas leak from a well which was being worked on. The amount of gas emitted from the well caused full evacuation and the fact that the problem was solved with no injury gives full testimony to the high standard of the Operators Policies and Procedures. The well was killed from the top and a relief well was also drilled, designed to kill the well from the bottom. Unfortunately, the cost of a) loss of production and b) remedial works ran into £billions and the Operator was fined £1,125 million by the Law Courts for contravening the Health & Safety at work act. Sometimes, during the early design phases of a project company departments make decisions which turn out to be less than optimal simply because certain information wasn't known. This can be unfortunate and very costly. The field, Elgin, was named after a relatively nearby Scottish town. The field forms a part of the Central Graben and there were essentially two reservoir columns (the Jurassic overlying the Pentland). The paper tries to portray the excellence of planning, management and operations exhibited by the current world class / first rate Operator.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 170584, “Dynamic Fault-Seal-Breakdown Investigation - A Study of Egret Field in the North Sea,” by P.P. Obeahon, SPE, G. Ypma, and O.U. Onyeagoro, SPE, Shell, and A.C. Gringarten, SPE, Imperial College London, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed.
The ability to predict the effect of faults on locating remaining hydrocarbon is critical to optimal well-placement, reservoir-management, and field development decisions. The tools and techniques available for realistic differentiation between sealing and nonsealing faults have presented a great challenge to the industry. This paper discusses the results of an integrated study that incorporated detailed geology and reservoir engineering to understand production behavior of a complexly faulted high-pressure/high-temperature field in the North Sea.
Predicting fault-seal breakdown is a challenging task because it involves many interrelated factors and complex relationships. Knowledge of these factors is both nonunique and subjective. Most faulting processes have been studied in isolation, and the relationships among many of the processes are understood poorly.
Reservoir depletion can, in principle, induce stress paths capable of reactivating intrareservoir faults and, hence, potentially cause breakdown of their sealing integrity. Fault-seal breakdown may also be invoked falsely where oil/ water contacts change across a fault (i.e., the fault is a capillary seal) but the fault does not compartmentalize pressures in production. This apparent seal failure can arise because of pressure communication in the water leg below the oil column. It is not clear why pressure depletion should cause capillary-seal failure. However, publications exist that attempt to attribute production behavior observed in fields to fault-seal breakdown in a production realm, because of pressure depletion on one side of a fault.
The first attempts to incorporate geologically reasonable fault properties into production-simulation models involved the calculation of transmissibility multiplier on the basis of absolute permeability and thickness of fault rocks. These calculations do not capture the multiphase behaviors of fault rocks. A key problem with this approach is that a huge number of pseudofunctions needs to be calculated to take into account the large variation in fault properties (e.g., thickness, absolute permeability) and flow rates and whether the fault is going through drainage or imbibition during production. The second attempt involved calculating transmissibility multipliers (also known as seal factors) on the basis of fault permeability. The key problem with this approach is that fault permeability depends on shale gouge ratio and fault displacement alone. The calculation does not capture the impact of reservoir permeability on fault permeability.
The ability to predict the impact of faults on locating the remaining Hydrocarbon (LTRH) is critical to optimal well placement, reservoir management, and field development decisions, particularly relevant for cost effective management of North Sea assets. Tools and techniques to realistically differentiate between sealing and non-sealing faults have presented a great challenge to the industry. This paper discusses the results of an integrated study that incorporates detailed geology and reservoir engineering to understand production behaviour of a complex faulted high pressure high temperature (HPHT) field in the North Sea. The fault architecture divides the field into 5 lateral compartments. Historically, fault transmissibility from lateral connectivity between compartments and changes of this property with depletion was recognized as a key subsurface uncertainty.
Oil-bearing Pentland and Skagerrak are key producing reservoirs of interest; Skagerrak reservoir with an average reservoir permeability of 50mD is the focus of the study. The initial reservoir pressure and temperature are 12500psi and 3400 F respectively. Production started in 1998 from well 22/24D-10 (southern fault block) and after producing slightly more than 1MMstb, rapid decline in reservoir pressure (~6000 psi) signifying no pressure support was observed. In 1999, a flattening of the pressure that extended to 2006 was observed. From Material Balance work, flattening of pressure was not expected until below bubble point if there is no change in connected Stock Tank Oil Initially in Place (STOIIP). Therefore, one hypothesis is that the observed pressure flattening could be as a result of cross fault flow that changed the connected dynamic STOIIP as a result of draw-down during production. Another hypothesis is that recharge could be through the aquifer. This study shows that fault seal failure is the most likely mechanism for pressure support.
Three main techniques used for investigating dynamic fault seal breakdown are presented. This includes proprietary Petrel FTM plug-in tool, production analysis and deconvolution. Static evaluation of faults using the Shell tool suggests initial sealing nature at initial conditions and the ability for the fault to breakdown given high enough pressure differential. Production analysis identified the weak faults. Deconvolution of the rate and pressure history reveals signature consistent with breakdown of a fault. The distance extracted from deconvolution is consistent with that from static evaluation. Also, 4D seismic signal is consistent with all interpretation of fault seal breakdown. Result shows that the first three compartments in the southern part of the field have been depleted and that there is across fault flow at or below 6000psi capillary threshold pressure.
It will be shown that using well test analysis technique; dynamic fault seal failure can be properly understood. It is hoped that this paper will guide and improve a petroleum engineer’s ability to account for dynamic nature of fault Transmissibility Multipliers during dynamic simulations.
Corrosion of metallic well and process materials can be caused by water that is co-produced with oil and gas. The corrosion processes involve electrochemical reactions that are dependent on the composition of the produced water. Variation of the produced water composition during oil and gas production can be investigated using electrolyte simulation tools that model the chemical reactions (chemical equilibria) that control the composition of the produced water. This paper describes how electrolyte simulation was used to investigate the failure of 2205 duplex stainless steel (UNS S31803) process pipework on the Shearwater installation, operated by Shell Exploration and Production, in the Central North Sea.
The failure of the 2205 duplex stainless steel (22Cr) involved stress corrosion cracking (SCC) initiated from both the outside and inside of the pipework. Cracks initiated from the outside were attributable to a known chloride SCC failure mode of 22Cr. The mechanism involved a high degree of evaporation of seawater on the pipework surface. However, the mechanism that initiated cracks from the inside was unusual because oxygen was not present. Electrolyte simulation tools were used to establish the chemical environment associated with the cracks initiated from the inside. It was demonstrated that evaporation of produced water, resulting from a 90 bar to 15 bar pressure reduction at ~136°C, had created brines with very high calcium and magnesium chloride concentrations. The resulting "exotic" brines had not been anticipated and were outside the range of environments for which the process materials had been qualified. Subsequent laboratory materials testing replicated the field failure in the presence of these brines.
This study highlights the need for materials selection to include rigorous evaluation of steady state and transient process environments using both electrolyte and hydrocarbon simulation tools. Special attention should be given to projects that apply materials and processing concepts in novel combinations. The failure illustrated that surface wetting of pipework can initiate corrosion failure even at very low water volume fraction (< 0.5 vol%).
The need for a fit-for-purpose cement sheath was recently emphasized in the HPHT Shearwater Field when annular pressures were observed on all but one of the production wells, either immediately or during the completion phase. Such annular pressures may result in an inability to produce the reservoir, which fully erodes the value of the asset.
The main objective of a primary cement job is to prevent formation fluids from migrating into the annulus so that the reservoir can be produced safely and economically. To achieve this objective, as a first step, cement slurry should effectively displace the drilling fluid in the annulus. The set cement sheath should then withstand the stresses induced by the well events and maintain integrity during the life of the well.
For the Shearwater Field, a rigorous design method was used to evaluate the integrity of the cement sheath as a function of its properties and formation characteristics. The design procedure was based on finite element modeling and simulated the sequence of events starting from the drilling phase, including cement hydration, well completion, and production.
This paper discusses ways to improve cement designs in the Shearwater Field. The methodology developed was used to optimize the design of future Shearwater wells, resulting in the specification of improved cement systems/methods. The criteria used to evaluate the cement sheath performance are discussed, as well as the effects of well events on cement systems for reducing the risk of damage.
The specification from this analysis was implemented in the field, and the optimized cement sheath withstood the stresses from well completions and other events. The new well is on production and all indications are that no annular pressure problems exist. Therefore, this design process can help improve the economics of constructing and producing oil and gas wells, resulting in a cost-effective life-cycle design. The process can also reduce health, safety, and environmental (HSE) risks because it minimizes the potential for zonal isolation failures.
This paper presents an overview of coiled-tubing (CT) innovations and perforating-tool enhancements that have been developed in recent years to meet the challenges of coiled-tubing perforating in high-pressure, high-temperature (HPHT) well environments in the North Sea, specifically on TotalFinaElf's Elgin and Franklin fields.
Key areas covered include: the manufacturing and inspection of coiled tubing; new pressure-control equipment for pressures up to 15,000 psi and temperatures up to 390°F; installation, operation, and maintenance of surface equipment; downhole tools; perforating tools; elastomers; well fluids; contingencies; best practices; and future solutions.
TotalFinaElf's Elgin and Franklin Fields are located in the central North Sea Graben Area, east of Aberdeen, Scotland. The two fields consist of 14 wells, in water 295 ft (95 m) deep, with the combined capabilities of 770 MM BOE reserves and a design rate of 170,000 bbl/day (14.6 MM m3) condensate. The reservoir conditions of these wells are rated at 16,000-psi (1,100-bar) pressure, 392°F (200°C) temperature, with formation depths of 18,000 ft (5,500 m).
The primary components of the completions consist of 4 1/16-in. Christmas trees, 5-in. 25% chrome tubing, safety valves with communication nipples, permanent production packers, and isolation packers specific to the Franklin Field (two reservoirs).
The Elgin field required single-run selective perforating of up to 200-m intervals with ± 2-m depth accuracy.
The Franklin field required selective perforating of up to 334-m intervals with ± 2-m depth accuracy for the two reservoirs. The second perforating operation was run in a live well. The depth accuracy was needed to avoid perforating high-permeability zones that would cause early sand production.
A number of perforating methods were considered, and finally, perforating through coiled tubing with an accurate depth-control system was chosen for the following reasons:
Only one or two runs would be required for the entire interval. In HPHT wells, minimal intervention is advantageous.
The method would allow at or underbalanced perforation.
Accurate depth control could be maintained.
There would be no requirement to drop the guns (a sump was unavailable due to drilling constraints).
However, the team also recognized that this method would require the development of some critical equipment and a careful selection of tools to achieve a safe and accurate execution.
On commencement of the project, a dedicated team was assigned to the operation from both TotalFinaElf and Halliburton. The primary requirements identified for a coiled-tubing system working in an HPHT environment were:
A CT string capable of running and pulling 330+ m of guns.
All critical parts of the system rated for worst-case conditions for the surface pressure-control equipment.
An accurate depth-control system that would not require feeding electric line through the coil.
A simple deployment system and gun connectors.
Perforating guns and firing systems qualified for 392°F (200°C).