In this study, a transient multiphase simulator has been used to characterize the fluid-hammer effects of well shut-in and start-up on the coupled subsurface and surface systems. The original work was performed by applying sensitivity analysis on a typical production system that includes well completion, wellbore, downhole equipment like packer etc., and the associated surface equipment like flowline, riser and valves. The data used in the study was taken from the published literature to summarize the general course of key factors that worsen the fluid-hammer effects. Fluid-hammer is also known as water hammer, a shock wave produced by the sudden stoppage or reduction in fluid flow.
Field operations such as pressure transient analysis, facility maintenance and workover require well shut-in process. For a typical production system, the resulted sudden rises in pressure can be critical because it has direct impact on equipment including unsetting of packer and may also cause possible damages to instrumentations. This paper provides estimates of the typical ratio of transient shock in pressure and flowrate over pre-condition values, and the duration of such pressure shocks. It also proposes the best location of the shut-in valve and the length of flowline to reduce the fluid-hammer effects.
This is a pioneering approach to integrated multiphase flow modeling of transient fluid-hammer effects, targeting flow assurance issues. This approach also can be applied to surface facility design and served as a guidance in field operation to avoid hydrocarbon leaks.
Zaini, Muhamad Zaki (Schlumberger WTA Malaysia S/B) | Rivero Colmenares, Maria Elba (Schlumberger) | Sepulveda, Willem (Schlumberger WTA Malaysia S/B) | Salim, Muzahidin Muhamed (Petronas Carigali Sdn Bhd) | Bela, Sunanda Magna (Petronas Carigali Sdn. Bhd.)
This paper will outline and discuss the processes involved from planning to conceptual design, detailed design, equipment preparation and onsite execution that has contributed to the successful offshore installation of Malaysia's first dual ESP system. It will also highlight the challenges and issues encountered throughout the project. The well was originally completed in 1989 as a single producer with gas lift. It is closed in 2004 due to high solid production. A workover operation was carried out in end of May 2011 to revive the well. The current producing zone was plugged and abandoned and the shallower producing interval is opened up and completed. Instead of continuing with the status-quo, gas lift strategy the well is completed with a Dual ESP system with bypass tubing, making it the first ever dual ESP installation in Malaysia.
Gas lift has been predominantly used as the main artificial lift strategy in the region. It's relatively ‘cheap' resources and simple application has been the main driver for oil operator to continue using it as their preferred option. However as the water cut increases and lift gas supply become limited there is a need to have a look on the so called ‘commodity' artificial lift application. ESP has been seen as one of the most attractive alternatives. The field's first conventional ESP installation with a backup gas lift system in 3 wells was installed in late 2008. In 2010 another ESP with pod configuration was installed. Ever since then, Bokor Project Management team has started to explore on the advancement of ESP system in order to find the optimized design for Bokor Field. However there are several challenges to be addressed.
· Justification to use a dual ESP system rather than a conventional gas lift system or single ESP configurations that has
been done previously in 4 other wells, especially in term of initial cost.
· The complex installation of a dual ESP system complete with bypass tubing and gas lift backup system which is not a
common practice in the area
· Design considerations and challenges for a successful installation.A complete design of a dual ESP for well specific
· Installation challenges of Dual ESP system with bypass tubing and backup gas lift system utilizing a hydraulic workover
unit which has limited handling capacity compared to a conventional rig.
· Surface requirement and limitations of the existing facility for ESP commissioning and startup.
Successful production in shale gas plays largely depend on identifying hydraulically fracable zones. Considerable lithological and petrophysical heterogeneity is expressed by changes in clay, silt, carbonate, and organic content. These changes correspond to variation of the dynamic rock mechanical properties. The contrast of rock mechanical properties amongst the layers influences the fracture dimensions. Detailed petrophysical analysis of shale gas reservoirs facilitates the mapping of the vertical and lateral distribution of various petrophysical and rock properties.
Identifying the most suitable zones for well placement, fracture initiation, and optimal distribution of proppant, maximizes the well performance. Geomechanical modeling in conjunction with the distribution of reservoir and rock properties, determined through detailed petrophysical analysis, can be used to determine the optimum lateral placement and fracture design in shale gas plays. Geomechanical modeling aids in estimating fracture dimensions, fracture conductivities, and also identify zones that can potentially inhibit vertical fracture growth.
This paper describes a petrophysical analysis workflow for analyzing shale gas well logs and how the results from the analysis may be used to identify potential lateral well placement targets. Sensitivity studies showing the influence of rock properties and changes in stimulation design on fracture growth are also presented.
Sand screens, including wire wrapped sand screens and slotted liners are often installed in sanding prone wellbores to control sand production. The selection of optimal sand screen aperture for a given sand body is critical to minimize sand production while maintaining well productivity. Laboratory sand retention tests were developed over 10 years ago to provide a basis for sand screen selection. Unfortunately, these experiments have a number of limitations. For example, the results can be substantially different depending on how the tests are conducted and data interpreted. This can lead to different (sometimes wrong) sand screen types and screen opening size recommendations.
This paper presents an initial investigation of the sand production problem from wire wrapped screens and slotted liners, through the use of discrete element model (DEM) for the solid flow with or without fluid flow coupling using computational fluid dynamics (CFD). The focus is on some key design and/or operating parameters affecting sand retention over the sand screen, such as the screen opening size, initial solid concentration, fluid flow velocity as well as particle shape.
Low permeability reservoirs contain a large volume of the world's oil resource. Often these fields are characterised by low waterflood injectivity, poor sweep and low productivity. A substantial number of these fields are initially, or during production become, fractured. Improved oil recovery and EOR for these fields is an attractive goal, although many conventional EOR applications present major challenges.
We present results on how wettability alteration, together with physical and chemical modifications of the waterflood, can improve oil recovery. From high precision adsorption experiments, together with wettability measurements on model systems, we present conclusions on the inter-relationship of adsorption behaviour and wettability of reservoirs.
Laboratory measurements are presented confirming how:
1. Wettability can be modified through changes in salinity, hardness and temperature.
2. In waterflooding there is a direct, measurable relationship between wettability (contact angle) and adsorption at the solid / liquid and liquid / liquid interfaces. These inter-relationships can be expressed in basic thermodynamic concepts.
3. Adsorption at solid / liquid interfaces can be directly related to the existence and nature of thin aqueous films in water wet and mixed wet reservoirs. Dynamic effects resulting from brines of different chemical and physical properties can be highly important in terms of displacement efficiency during waterflooding.
We demonstrate the significance of these results for waterflooding and EOR in lower permeability fields. Approaches such as wettability alteration, low salinity (including brine compositional modification) waterflooding, and variation of injection brine temperature all show potential. This is in contrast to more traditional chemical and immiscible gas injection, which are often technically difficult in these fields. We further conclude that these approaches can be beneficially applied fields with substantial fracturing and faulting.
The advent of unconventional petroleum resources has radically altered the landscape when it comes to project development. Most of the traditional methods to predict reserves are no longer useful. This paper will review the traditional evaluation practices and recommend improvements.
Forecasting conventional oil and gas reserves has traditionally been done using Arps equations that were designed for Boundary Dominated Flow (BDF), but unconventional wells may experience transient flow for up to a decade or more before the onset of BDF. Arps requires the combination of a super-hyperbolic period that smoothly transitions to an exponential tail to model this unconventional behavior. Unfortunately, the Arps equations offer no information as to when this transition occurs. A new class of empirical decline equations, termed stretched exponentials, is gaining favor in forecasting shale oil or gas. These equations are beneficial because an exponential period is not required. This paper will review the three most popular methods and compare them to Arps. Other decline issues covered include: how much data is necessary to provide a reliable forecast, and how to efficiently forecast hundreds or thousands of wells.
When building type wells, it can be challenging to obtain statistically valid and significantly similar wells. For instance, fracture size, fracture fluid type, completion technique, well location and many other factors may need to be considered in order to obtain meaningful groups. This paper will suggest possible groupings and propose methods to confirm their validity.
This paper will also demonstrate that type wells created with only historical data, as is standard practice, are logically flawed. When historical production data is merged with reliable production forecasts to build a type well, the resulting type well is the best available representation of the underlying data. A detailed review and analysis of the type well equations plus real-world examples will demonstrate this point.
Water flooding is a commonly used technology for enhancing oil recovery. Its mechanism is to maintain higher pressure in reservoir and to sweep the oil from the reservoir and push it towards production wells. However the strong water flooding will cause higher compression pressure around the injection wellbore. This high pressure in the reservoir causes stress redistribution and higher stress near the wellbore which induces material damage and permeability change. We developed a fluid-solid coupling finite element model to simulate and quantitatively analyze the pressure evolution in the reservoir as well as damage and permeability change in the formation during long term water flooding process. The obtained results offer theoretical understanding on the benefits (pore pressure increase in the simulation domain), rock damage, permeability change of long term water flooding and the insights of how to detect and prevent wellbore failure and collapse due to water flooding.
Key words: water flooding, oil recovery, rock damage, permeability change, numerical simulation
This discussion paper concerns the critical role leadership plays on safety behaviour in the innately hazardous environment of oil and gas installations. It has been demonstrated on a number of occasions that safety culture is a major determinant of either positive or negative safety behaviour. In turn it is clear that managers at all levels on a rig can determine the safety culture though the emphasis they place on safety in all that they do. It has also been shown that transformational and transactional leadership styles are much more effective in developing a positive safety culture than authoritarian and passive styles. Positive psychology is a relatively new concept in psychology that emphasises an optimistic view of people and the world, of possibilities and what can be done. The approach provides a number of easily learned techniques that can improve leadership style and safety culture as part of the essential war on fatalities and injuries.
Safety Climate on Oil Rigs
It is reasonably well understood that an oil and gas rig, land or sea based, is a potentially unsafe environment in which to work. According to the International Association of Drilling Contractors there were, world wide in 2009, 32 fatalities, 1089 medical treatment incidents, 716 restricted work incidents, and 744 lost time incidents, recorded by 125 participating companies. This is a total of 2581 recordable incidents equating to a frequency rate of 6.12 per 1,000,000 person hours of work. If transportation and other activities not directly associated with drilling or production are included, then recordable incidents and fatalities rise. For example, with these inclusions there were 99 fatalities in 2009 and 94 in 2010 according to the International Association of Oil and Gas Producers. The 2010 figures include the 11 workers killed in the Deepwater Horizon disaster in the Gulf of Mexico and 21 killed in a plan crash in Pakistan. It is encouraging that the rates of recordable incidents in all categories have declined over recent years and certainly since the Piper Alpha and Valdez incidents in 1988 and 1989 respectively, galvanized the attention of the industry. Nonetheless, as the 2009 report from the International Association of Drilling Contractors noted, even though there has been vast improvement in safety over the years, 32 fatalities is too many.
According to Turner and Pidgeon (1997), most industrial accidents involve a causal chain of organizational conditions and human error. Decreasing the likelihood of equipment failure will and does decrease the possibility of accidents in inherently dangerous work. Similarly, improvements in HSE management systems, resources, competence training, integration of HSE into business and operational safety (Curlee et al, 2005) are essential. Hase and Phin (2012) indicate several areas that provide a focus for improving safety on onshore and offshore installations. These include: adequate resources; daily rig safety (housekeeping, state of the rig, equipment, reporting near misses); process systems (JSAs, after action review, use of observational tools, policies and procedures); quality of induction and follow-up; and continuous improvement.
Slugs-fracs is one of new-to-field approaches which changed the conditions of wells for fracturing increasing the number of candidates in Kamennoe field Western Siberia. Placing fracturing jobs by slugs of proppant pumped in linear gel successfully implemented in stimulating pay zones in near water intervals with small stress contrast between zones and barriers. A few technical specifics had been used to contribute the success of this methodology such as earlier pumping with near matrix rate to allow more fluid filtration ahead of the main proppant stages before fracture is fully formed. Proppant setting according to Stokes law and dune effects theory were evaluated and considered for design strategy. The slugs-fracs allowed pumping regardless of the wellbore deviation and height of perforated intervals. Post-fracturing results from 120 wells were used for analysis. Significant decrease in initial water cut and sustainable oil production were reported. First slugs-fracs were introduced in the beginning of 2010 and in following 2 years more than 200 hundreds jobs have been pumped across the field. This allowed to drill spots of the field that were previously suspended as result of ineffective fracturing treatments mostly due to high risk of fracture breaking down the water zones.
Introduction and application of technology
This paper describes a new approach in hydraulic fracturing used for Kamennoe field in Western Siberia. Selected technique allowed to reassess the conditions of wells selected for fracturing. As result it allowed to involve more reserves into development of the field. Approached fracturing technique used slugs-frac pumping method to transport proppant into formation. Fracturing fluid was guar based linear gel with 1.8 to 2.0 kg/m3 of polymer loading. Chosen combinations lead to successful post-fracturing results. Post-fracturing water production was the main measure in rate of success within this study. Stimulated wells were with pay zones in near water conditions with small stress contrast between productive zones and barriers. Those barriers control the fracture height propagation based on geo-mechanical modeling (fig. 15a, 15b).
Slugs-frac is a pumping technique which consists of several proppant slugs pumped in between spacer pads. Fracturing fluid is a linear gel. In some occasions this technique is combined with crosslinked gel stages pumped usually at the end of the treatment in tail stages. The following technical specifics were embraced into design to aim the success of this methodology. First portion of pad including tubing volume ahead were pumped at matrix rate of 1.2 to 1.4 m3/min. It made excessive fluid filtration before fracture is fully formed prior proppant stages were introduced to formation (fig. 9). Pad volumes were in the range of 2 to 5 % of slurry volumes to limit the geometrical fracture volume. Proppant settling was simulated according to Stokes law or fall correction factor using the simulation software. The dune (bed) effects theory was evaluated and considered for design methodology (fig. 8). Most of wells are s-shaped and highly deviated due to drilling from pad locations which is a common practice to drill in marshland conditions of Western Siberia. Because of that many wellbores were not along with fracture plane propagation. In those wells the wellbore angle at perforation interval was more than 30 degrees. The slugs-fracs made possible the successful placement of treatments regardless of the wellbore deviation and height of perforated intervals. At described conditions the first slugs of proppant played an additional role of eliminating the potential problems with wellbore tortousities and premature screenouts.
Pentland, Christopher Holst (Shell Netherlands Natural Gas) | Iglauer, Stefan (Curtin University) | Gharbi, Oussama (Imperial College) | Okada, Katsuhiro (University of Tokushima) | Suekane, Tetsuya (Tokyo Institute Of Technology)
We investigate the characteristic properties of porous media that influence the entrapment of carbon dioxide (CO2) by capillary forces. It is known that different geological formations can trap different quantities of CO2 but the relationship between formation properties and trapping is poorly understood at present. Advances in micro computed tomography (µCT) techniques now allow the porous media and trapped CO2 clusters therein to be visualised and characterised on the micro meter scale. The context of this work is the geological storage of CO2 where the entrapment of injected CO2 by capillary forces on the pore scale is proposed as a fast and safe method to store injected CO2.
We analyse a series of saturated and unsaturated porous media using µCT; four glass bead packs, a sand pack and a sandstone. In the saturated images the pore space contains brine and residual CO2 (Sr) at subsurface storage conditions. We quantify Sr and cluster size distributions and determine characteristic properties of the porous media through image analysis and the extraction of representative networks. We show that media with narrower pore throats, such as sandstones, trap more CO2 than media with wider pore throats. Numerical simulations performed on the extracted networks do not accurately predict the measured residual CO2 saturations. We discuss the important implications of these results for CO2 storage site selection, containment security assessments, and storage capacity appraisal.
Capillary trapping - the immobilisation of non-wetting phase clusters on the pore scale by capillary forces - has been identified as an important subsurface mechanism in the geological storage of CO2 in saline aquifers. The magnitude of CO2 trapped by capillary forces (the residual saturation; Sr) will impact the migration of CO2 through the aquifer and the ultimate CO2 storage capacity, while the surface area of trapped clusters will be a controlling parameter in their ultimate dissolution in the formation brine.
Capillary trapping has been studied for decades due to its importance in the petroleum industry and in soil remediation, and more recently also in the context of CO2 storage (e.g. Jerauld, 1997, Conrad et al., 1992, Iglauer et al., 2011a respectively). Historically experiments were performed on centimetre scale samples (e.g. Oak et al., 1990) but recently such experiments have been performed on millimetre scale samples enabling the pore space and the fluids contained therein to be imaged on the micro-meter scale with micro-computed tomography (µCT) [Prodanovic et al., 2007; Iglauer et al., 2010, 2011b, 2012a, 2012b; Kumar et al., 2010; Georgiadis et al., 2011; Suekane et al., 2011; Porter et al. 2010].
Here we perform additional analysis on the storage condition (i.e. high pressure and elevated temperature) CO2-brine results of Iglauer et al., 2011b and Suekane et al., 2011. Table 1 summarises the conditions of these experiments. Our objective is to understand which characteristic properties of the porous media have the greatest influence upon capillary trapping, and to investigate the characteristic properties of the trapped clusters. We employ a multi stage approach: rock properties are determined from the unsaturated scans through image analysis and the generation of representative pore network models; cluster properties are determined by analysing the saturated scan images; and trapped CO2 saturations from the experiments are compared with those predicted by dynamic simulations on the pore network models.