When a current impacts on a circular pipe, fluctuating forces are created due to vortex-shedding in the wake. In offshore industry the interest for vortex induced vibration (VIV) is focused on the fatigue that pipe can experience. The fatigue due to VIV can be the dominant fatigue in some pipelines, subsea structures and risers.
The assessment of VIV fatigue for pipelines and subsea structures involves two steps. The step one is to determine the structures response under the combined current and/or wave conditions, using analytical, semi-analytical or numerical approach. The second step is to identify the hot spots in the structure and process their loading states to calculate the corresponding damage or life, such as using S-N curve, which is a common practice in the industry. Since simulating the structures response under fluid loads is the key challenge in the VIV fatigue assessment, this paper focuses on the first step with an emphasis on the FSI approach.
The current study developed a finite element model in the frame work of the ABAQUS that can be used in the cross flow VIV analysis of the pipelines and jumpers. The fully three dimensional computational fluid dynamics (CFD) solutions are combined with structural models of pipeline and jumper to predict vortex induced motion. The use of three dimensional CFD solutions is aimed to eliminate the guess work for VIV analysis. The proposed method uses finite element methods that are tolerant of sparse meshes and high element aspect ratios. This allows economical solutions of large fluid domains while retaining the important features of the large fluid vortex structures. The method can also be extended to sheared currents whose velocity varies with depth. The proposed method is applied to pipeline and jumper and benchmarked against published results. It also confirms the validity of the simplification of a jumper to a straight pipe during jumper VIV analysis based on DNV RP-F105, which is a common practice in offshore industry. The developed model might be used to reduce the conservatism in the fatigue assessments of pipeline guided by codes, such as DNV RP-F105.
Operators of steamflood projects seem to prefer low pressure steam zones in their operations. The difference between steam zone temperature and initial reservoir temperature drives all energy requirements, which are usually the largest single cost in a steamflood project. However, lower steam zone pressure implies lower drawdown available for production. And lower steam zone temperature implies higher oil viscosity and therefore lower oil production rate. The influence of steam zone pressure and temperature on oil production rate is large. Theoretically, the influence on ultimate recovery (residual oil saturation) is moderate to none. Since costs encourage lower steam zone pressure and productivity encourages higher steam zone pressure, there should be an economic optimum.
The rate of change of energy requirements and oil production rate with respect to changes in steam zone temperature and pressure are determined analytically. If the reservoir geology is conducive to gravity drainage, even by a very tortuous path, then low steam zone pressure is highly favored. Lowering steam zone pressure usually comes at the cost of increased withdrawals, so it is important to carefully consider the requirements, consequences, and benefits on a case-by-case basis. A recommended method for this analysis is discussed. Significant project improvement after a pressure reduction has been reported. These production improvements and steam zone pressure in major steamflood projects are discussed.
Operators prefer to keep steam zone pressure as low as possible since pressure and temperature have a one-to-one relationship, temperature level above initial temperature drives all energy requirements (energy for steam zone growth, energy for heat losses, and energy produced and lost from wellbores and pipelines), and energy required for a steamflood project is usually the largest single operating cost. Some documented projects have steam zone pressure lower than tire pressure. A sampling of industry experience is given in Table 1.
In addition to the cost side, there is an incentive to develop as large a steam zone as possible. Several papers show pre-steam and post-steam core analyses with noted oil saturation changes. In Kern River Field, for example, "oil saturation is significantly reduced wherever a steam zone develops and is only slightly reduced in an underlying hot water zone?? (reference 2).
Duque, Helman (Halliburton) | Ramirez, Carlos Andres (Halliburton) | Quinn, Dan (Halliburton) | Rodriguez, Yerayen (Halliburton de Venezuela) | Jaramillo, Jose Arturo (Maurel et Prom Colombia) | Ruiz, Juan Camilo (Maurel et Prom Colombia)
New areas of oil exploration in Colombia are usually located in complex geological settings where conventional surface seismic data is traditionally of poor resolution. The recent improvements in borehole seismic software applications has made it possible for real-time vertical seismic profile (VSP) processing at wellsite to provide time-critical information with improved vertical resolution. This advancement has promoted the use of VSP applications in complex areas, as is the case of the zero-offset vertical seismic profile (ZVSP) data that was acquired in an exploration well in the Cordillera basin of Colombia. The real-time results obtained by processing the VSP data at the wellsite shortened the decision-making process (reduced NPT); in this case, it aided in the decision to invest additional resources to continue to drill a reflector observed on the VSP below the initial target. This case history describes the real-time wellsite application of acoustic impedance inversion of the upgoing waves and prediction ahead of the bit. In this example, the new target was encountered 5 ft below the prediction. The acquisition and processing of this data reduced uncertainties and verified the new target below the bit.
The results of the theoretical model and the actual data demonstrate that the method is effective for pre-drilling predictions using borehole seismic data; these results also make the VSP a powerful tool for making decisions during the drilling stage of the project. This paper describes the acquisition, processing, and method used to help improve subsurface imaging and to predict the depth to the reflectors ahead of the bit.
This paper will review the history and current operations of the Kuparuk River Unit (KRU) field, the second largest field on the North Slope and one of the largest fields in the US. The field is a legacy asset in the ConocoPhillips portfolio with more than 6 BBO OOIP. The field came on line in December 1981 and has produced 2.25 BBO to date through water flood, immiscible water-alternating gas (IWAG) and miscible water-alternating-gas (MWAG) injections. Currently the field produces 90,000 bopd, 460,000 bwpd and 210 MMscf/d gas, and injects 570,000 bwpd and 160 MMscf/d miscible injectant.
Some of the recent challenges at KRU include: maintaining pressure support (water injection) through an aging infrastructure, development and use of fit-for-purpose simulation models to support field management decisions, estimation of facilities back-out from a complex multi-field system, and optimization of one of the largest MWAG EOR floods in the world. History and current status of the KRU field will be discussed.
Lost circulation caused by low fracture gradients is the cause of many drilling related problems. Typically the operational practice when lost circulation occurs is to add loss circulation materials (LCM) to stop mud from flowing into the formations.
To improve the treatment for lost circulation caused by low fracture gradients, especially designed materials in mud system are used to seal the induced fractures around the wellbore. This operation is in the literature referred to as wellbore strengthening that has been found to be a very effective in cutting Non-Productive Time (NPT) when drilling deep offshore wells. Size, type and geometry of sealing materials are debating issues when different techniques are applied. Also the phenomenon is not truly understood when these techniques applied in different sedimentary basins.
This paper presents development and simulation results of a three-dimensional Finite-Element Model (FEM) for investigating wellbore strengthening mechanism. This study also describes a procedure for designing Particle Size Distribution (PSD) in field applications. To better understand the numerical results, the paper also reviews the connection between Leak of Tests (LOTs) and wellbore hoop stress and how these LOTs can mislead in fracture gradient determination.
A comprehensive field database was collected from different sedimentary basins for this study. Results demonstrate that the maximum attainable wellbore pressure achieved by wellbore strengthening is strongly controlled by stress anisotropy. Results also show that Particle Size Distribution (PSD) of wellbore strengthening should be designed in order to seal the fractures close to the mouth and at fracture tip. This will result both in maximizing hoop stress restoration and tip-screening effects. In addition this model is able to show the exact fracture geometry formed around the wellbore that will help to optimize the sealing materials design in wellbore strengthening pills. To support numerical modeling results, near wellbore fracture lab experiments on Sandstone and Dolomite samples were also presented. Laboratory experiments results reveal importance of rock permeability, tensile strength and fluid leak-off in wellbore strengthening applications.
Narrow pore-fracture window in deep and ultra-deep offshore environments, highly deviated wellbores and depleted formations is the most prominent drilling challenge today. Lost circulation and high non-productive time due to the tight window is the major motivation for widening operational window and using wellbore strengthening techniques. Wellbore strengthening can be defined as "a set of techniques used to efficiently plug and seal induced fractures while drilling to deliberately enhance the fracture gradient and widen the operational window??. This technology has the potential to mitigate the lost circulation problem, and improve wellbore integrity to avoid well control disasters. In addition, it might reduce the number of casing strings required to drill deep water wells.
Previous joint industry projects (DEA-13 and GPRI) conducted experiments to investigate lost circulation. The main finding from these projects was the ability to increase fracture reopening pressure by using specific type and size of materials in the drilling fluid system (Morita et al., 1996a, b, and Dudley, 2001). Investigating the physical mechanism that enhances the fracture gradient was not truly feasible using these experiments. Therefore, a clear understanding regarding the effect of material properties (size, type and strength) of the actual sealing mechanism was never achieved but spurred continuous investigations on how drilling fluids can improve the fracture gradient. Table 1 summarizes the wellbore strengthening methodologies, whereby some of them differentiate in the mechanism involved, material type and strength to be used plus the necessity for tip isolation.
During hydraulic fracturing operations in low permeability formations, spontaneous imbibition of fracturing fluid into the rock matrix may be responsible for having a significant impact on the retention of water-based fracturing fluids in the neighborhood of the induced fracture. This may consequently affect the post-frac productivity of the well. However, there is lack of direct quantitative and visual evidence of the extent of retention, evolution of the resulting imbibing fluid front, and how they relate to potential productivity hindrance. In this paper, laboratory experiments have been carefully designed to represent the vicinity of a hydraulic fracture. The evolution of fracturing fluid leak-off is monitored as a function of space and time using X-ray computed tomography (CT). The X-ray CT imaging technique allows us to map saturations at controlled time intervals to monitor the migration of fracturing fluid into the reservoir formation. It is generally expected for low permeability formations to show strong capillary forces due to their small characteristic pore radii, but this driving mechanism is in competition with the low permeability and spatial heterogeneities found in tight gas sands. The relevance of capillarity as a driver of fluid migration and retention in a tight gas sand sample is interpreted visually, quantified and compared with high permeability Berea sandstone in our experiments. It is seen that although these formations demonstrate strong capillarity, the effect can be suppressed by the low permeability of the formation and the heterogeneous nature of the sample. However, saturation values attained during imbibition experiments are comparable to those previously obtained for high permeability samples, which can have significant implications in terms of phase mobilities in the neighborhood of induced fractures. Results from this investigation are expected to provide fundamental insight regarding critical variables affecting the retention and migration of water-based fracturing fluids in the neighborhood of hydraulic fractures, and consequently on the post-frac productivity of the well.
Gas drilling has many advantages such as high drilling speed and reservoir protection, however, there are many problems limiting its development. For example, when gas drilling encounters geological risks, drilling fluid must be filled. The process of gas-liquid medium transition will make liquid flow into the fractures in the rock around borehole wall, which may lead to serious borehole wall collapse. In this way, the problems brought by gas drilling counteract its advantages. Thus, this paper puts forward using nanotechnology to reverse the wetting of hole-wall rock before filling drilling fluid into the well bore. The core of this technique is the application of the high-speed gas current jetted by the nozzle of bit to atomize the solution. The low-activity and low-tension solution will carry nano wetting reverse agent and shale anti-swelling agent to ascend with gas along borehole wall. In this way, the dry rock will absorb the solution with agent, and the wetting of fractures can be reversed. After drilling fluid is filled. The capillary effect can prevent further penetration of drilling fluid, and the film on the fracture can avoid the swelling of argillaceous earth. Thus, the fracture won't expansion on the surrounding rock of the borehole. Compaired with existing techniques, the strength of the borehole wall can be improved by 50% by taking advantage of this technique. Instead of the previous research method from perspective of drilling fluid, the technique can directly change the nature of fracture surface with small amount of treating agent to avoid the expansion of fractures. Besides, the technique can effectively reduce the friction between drilling pipe and borehole wall. The technique is expected to avoid the problems of high cost, pollution, ineffectiveness, and achieve the goal of keeping the wellbore stability in gas liquid medium transition in gas drilling process.
Data rooms are inevitable whenever companies desire to acquire or divest oil and gas assets. They can be physical, i.e. a secure room with data placed within it, or virtual, i.e. an online data archive that can be accessed via a secure web portal, or a combination of both. If the data room visit by the prospective buyer's Mergers and Acquisitions (M&A) team lacks the necessary forethought and planning, it may not achieve its objective and the potential deal may be delayed, or even not go ahead at all.
This paper presents a framework to enable quicker evaluation of potential investments, while ensuring due diligence is taken when auditing estimates of resources and reserves. The framework is created for M&A teams with a wide range of experience and expertise, from newcomers to those who have spent too many hours in them.
Examples of real-life data room situations are given to illustrate how the framework is implemented. Advice is given on what data are essential to acquire versus those that are nice to have, depending on what the prospective buyer wishes to achieve. The challenge of selecting the appropriate make-up of the M&A team is also addressed. The framework gives clear and concise advice on what team members should do before, during and after the data room visit. Prioritized data lists are provided for each M&A team member, specific to their technical discipline, and key investigative questions to ask the seller are suggested. Time-saving ideas are proposed that can speed up any valuation in order that prospective buyers can quickly assess opportunities.
Finally, the paper describes some pitfalls that are inherent in any oil and gas asset evaluation, but which may have been avoided if the framework had been followed.
Steady increases in natural gas transportation volumes have prompted operators to reevaluate the performance of the existing gas pipeline infrastructure. In order to accomplish an increased transportation capacity, conventional wisdom dictates that adding an additional link or a pipe leg in a gas transportation network should enhance its ability to transport gas. Several decades ago, however, Dietrich Braess challenged this traditional understanding for traffic networks. Braess demonstrated that adding extra capacity could actually lead to reduced network efficiency, congestion, and increased travel times for all drivers in the network (the so-called "Braess Paradox??). The study of such counter-intuitive effects, and the quantification of their impact, becomes a significant priority when a comprehensive optimization of the transportation capacity of operating gas network infrastructures is undertaken. Corroborating the existence of paradoxical effects in gas networks could lead to a significant shift in how network capacity enhancements are approached—challenging the conventional view that improving network performance is a matter of increasing network capacity. In this study, we examine the occurrence of Braess' Paradox in natural gas transportation networks, its impact and potential consequences. We show that paradoxical effects do exist in natural gas transportation networks and derive conditions where it can be expected. We discuss scenarios that can mask the effect and provide analytical developments that may guide the identification of paradoxical effects in larger scale networks.
Sand production is a major operational and economical concern in the oil industry due to the potential risk of well failure, limited productivity, erosion of facilities, and increased operating expense. Experimental studies play an important role in understanding the behavior of sand production under different conditions. However, the existing traditional sand production experiments such as thick-walled, cylinder approach or perforation collapse test are only able to predict the onset of sanding and cannot be used to analyze sand production performance over time. In this work, preliminary empirical sanding prediction was performed based on well log data and the formation mechanical properties. The steady-state core flooding tests and core swelling tests were applied to simulate and investigate how the volumetric sand production changes with different flow rates, water saturations and the salinity of injected water. The cores and crude oil samples from an unconsolidated sandstone reservoir in China were used in the tests. The sand flow rate, accumulative sand volume and relative permeability were measured during the sand production process.
The experimental results indicated that the sand production rose at the beginning and declined with the increase of flow rate. During the early water-free production stage, the skeleton sand was not destroyed under realistic reservoir/well flow conditions so that the oil production with sanding was preferred. However, as water saturations increased from 20% to 80%, the permeability decreased by 80% accompanied by dramatic increase in sand production. This is due to the high content of Kaolinite, Illite and Montmorillonite with weak cement in the core which swells significantly and blocks the porosity once it is subjected to the water influx. Therefore, sand control should be considered when water saturation is over 20%. The change of sand production rate demonstrated that both the transient and continuous sand production could be involved in this reservoir. In addition, it is expected that the lower salinity of injected water aggravates the sand production.