Gyda is a mature oil development in the Norwegian sector of the North Sea. The first production wells were drilled more than twenty years ago. This study focuses on wells drilled in the porer reservoir quality areas of the Gyda reservoir. Some recent production wells have significantly underperformed relative to equivalent initial wells. In particular, a sidetrack to an early successful well, had very poor performance on initial start-up.
The geometry of the original well and the sidetrack were simulated, together with various assumptions and sensitivities to formation damage. In the original well an attempted hydraulic fracture had been assumed to have failed. This assumption was challenged in the model.
The model demonstrated that the original well must have included a successful hydraulic fracture in order to flow at the historical rates recorded. In addition for the sidetrack, that contained no fracture, there were indications that the perforation tunnels may not have fully cleaned up and that whilst the well performance may recover somewhat with time, a significant change in completion would be required in order to match the performance of the original well.
The model constructed included the completion geometry and formation damage and has enabled evaluation of old wells and more importantly, design of new wells in this mature reservoir development.
Some recent wells drilled on Gyda have not fulfilled the production objectives. A numerical 3D model was proposed in order to investigate and understand the flow dynamics and the production potential from the Gyda A19 and A19A wells. This modeling process includes a detailed numerical fluid flow simulator based on Computational Fluid Dynamics (CFD) which captures the reservoir, well and completion geometry complexity (Byrne et al, 2009 and 2010).
The CFD simulations are used to determine potential explanations for the wells performance and lead to stimulation options and development of optimum drilling and completion for future wells. The Senergy Wellscope modeling process has the stated objective of better production through better prediction. As the A-19 well is very similar to the A-19A well from Gyda, some conclusions may be derived from the present study which could support the understanding of the productivity behaviour of the A19A well.
To achieve the objective one base CFD model was constructed to represent the two wells to be evaluated (A19 and A19A). Different completion options were included, including the case of the well hydraulically fractured. Several sensitivities were carried out in order to depict the well potential.
Throughout the project, regular contact was held between the Senergy and Gyda team. These helped to frame and direct the project as well as providing necessary feedback on data gathered and model construction.
Nishikiori, Nobuo (Norske Shell A/S) | Sugai, Keiichiro (Arabian Oil Co. Ltd.) | Normann, Clas (Talisman Energy Norge AS) | Onstein, Arne (Talisman Energy Norge AS) | Melberg, Oddbjoern (DONG Norway) | Eilertsen, Terje (DONG Norway)
This study describes an improved engineering workflow to perform technical evaluation and screening of gas injection EOR. A successful case study demonstrates how field data, engineering analysis and simulation are integrated to precisely model gas injection EOR. This workflow can be adaptable for any type of reservoir and can be utilized as a fast-track screening workflow for gas injection EOR.
The target for this study was the Gyda reservoir located in the southern part of Norwegian North Sea in the Norwegian Continental Shelf. The reservoir is of heavily faulted heterogeneous shallow marine sandstone. As the measure of heterogeneity, a Dykstra-Parson's coefficient1 (VDP) of more than 0.8 has been measured from core plug data.
For the purpose of building a tool that can be utilized for gas injection EOR study, a five-step workflow has been implemented:
The results of this case study confirmed the capability of the described workflow to model gas injection EOR for the heterogeneous sandstone reservoir. Potential gas channeling in high permeability streaks and an improved displacement by gas was precisely modeled by the workflow. Injection strategies, such as WAG, SWAG and gas injection have been screened by the model, leading to a conclusion in relatively short period of time.
Sulphate concentration of produced water is a controlling factor in the scaling tendency of sulphate minerals (BaSO4, SrSO4 and CaSO4). In reservoirs under seawater flood, where the formation water is calcium-rich (>5,000 mg/l), and the reservoir temperature is above moderate levels (>100oC), produced water sulphate concentrations, sulphate mineral scaling potentials and therefore scale mitigation costs are often lower than expected due to deposition of sulphate scaling minerals in the reservoir. To obtain more realistic predictions of sulphate mineral scaling potentials and scale mitigation costs there is significant interest in trying to understand the factors controlling produced water sulphate concentrations and to simulate these data.
Various models have been used to simulate produced water sulphate analyses but only reactive transport reservoir simulators incorporate the capability to model the most
important factors determining produced water sulphate concentrations: reservoir reactions and mixing in and around the wellbore. However, even in this case the underlying
reservoir models are often uncertain and the approach costly and time-consuming.
In this study we present a new, two-water mixing model which assumes that water entering a production well is simply a mixture of (a) formation water and (b) an equilibrated mixture of formation water and seawater from which sulphates have precipitated in the reservoir (mixing zone water). This model can be used to explain trends in produced water scaling ions where lower than expected sulphate mineral scaling potentials are observed. By matching trends in produced water scaling ions, the model can be used to determine the variation in production proportions of the two waters, their compositions and seawater contents over time.
When applied to wells of the Clyde Field, trends in sulphate and barium produced water analyses are found to reflect a reduction in the proportion of formation water and an
increase in that of mixing zone water (and its seawater content) over time. For Gyda wells, the same results were obtained except that later in production, production of
formation water ceases and two different mixing zone waters are produced.
The model results are what would be expected for wells being progressively affected by a seawater flood and they have also been used to provide reasonable predictions of
concentrations of other scaling ions in the produced water. Therefore, although the model is a significant simplification of mixing conditions in and around the well, it does appear to provide reasonable results that are easily obtained.
The model results have a number of possible uses including (a) explaining trends in produced water scaling ions and lower than expected sulphate mineral scaling potentials, (b) providing alternative data for undertaking well scaling potential calculations and determination of laboratory MICs, (c) helping identify inadequately preserved samples and (d) potentially constraining the reservoir model.
The Varg field (PL038, Block 15/12) is located in the Norwegian Sea. The Varg reservoir is Oxfordian sandstone of Jurassic age, with an upper (1000-2000 mD) and lower (100-200 mD) sand separated by a mud rich sandstone. The field is highly compartmentalized and is located around a salt dome, and contains a number of different formation waters ranging from high salinity, higher barium (up to 280 mg/l) in the West and lower salinity and lower barium (30 mg/l) in other areas. All waters contain naturally occurring dissolved iron at concentrations up to 175 mg/l. Following scaling in several wells, a chemical re-selection and treatment optimisation programme was initiated. Extensive laboratory studies were undertaken to select optimum inhibitors, which was further complicated by environmental requirements. The presence of dissolved iron was shown to have an adverse effect on the incumbent scale inhibitor, leading to the selection of a number of alternative products. Given the highly compartmentalized nature of the reservoir and the large permeability contrast between zones, near wellbore modelling studies, examining chemical placement using both conventional (aqueous) based treatments and also viscosified treatments, were conducted. The potential for poor placement and subsequent poor lifetimes led to further detailed simulation work using up to date PLT logs to further refine the treatments in subsequent wells. Therefore, this paper describes the various challenges facing scale control in the Varg field. The paper presents results from a chemical re-selection exercise showing the controlling influence of dissolved iron, together with coreflood studies used to select the most effective non-damaging product for subsequent field trials. Extensive near wellbore modelling results are presented to illustrate the challenges faced with respect to effective chemical placement, which highlight the challenges faced. Several field trials have now been conducted with a new chemical and the results of these are also discussed.
Introduction & Challenges
The Varg field is located in block 15/12 of the Norwegian Sea (Figure 1) at a water depth of 86m, and came on stream in December 1998. The wells are tied into the wellhead platform Varg A, and the oil is processed at the FPSO Petrojarl Varg (Figure 2). The distance between the well head platform and the ship is 1 km. The oil is exported by tankers and the produced gas re-injected. The Varg reservoir is Oxfordian sandstone of Jurassic age, with upper and lower sands separated by a mud rich sandstone. The upper sand, which is mainly deposited in the south, is of good quality (permeability range 1000-2000 mD). The lower sand is of more variable quality with an average permeability around 100-200 mD with some zones significantly lower. The field has a complex fault pattern, especially close to the salt dome. There are strong tectonian forces in the area and the seismic has poor resolution due to overlaying chalk. This limits the sensitivity of the reservoir description used in the full field model and makes accurate assessment of the water sweep patterns difficult. There are different fluid properties in most wells, consistent with the highly compartmentalized nature of the field and the field consists of several PVT regions. Most of the wells are vertical or normally deviated cased, cemented and perforated wells with relatively short pay zones from different formation zones. There are also horizontal wells, the longest horizontal being about 1000m long, again producing from different zones. Most of the wells have gas lift due to low reservoir pressure. Carbonate scaling is relatively insignificant in this reservoir with the main challenges associated with barium sulphate scales both relating to self scaling issues and also mixing of reservoir formation waters with injected sea water.
Coiled Tubing (CT) equipment in the Norwegian sector of the North Sea has traditionally been heavy, due to CT reels using larger sizes of CT - a trend also observed in other areas. Due to the requirement of performing well interventions in longer wells and larger completion sizes, CT drums weighing 40-60 t have been utilised. Not many platform cranes are capable of lifting such heavy CT drums and during bad weather periods operations are often delayed, even when using significantly lighter CT drums. Using spoolable CT connectors allow for a long and heavy CT string to be lifted on board of a platform on two or more separate drums and joining them together again once onboard. More than 50% weight reduction has been achieved making operational schedules more predictable. In the geographical areas considered, spoolable CT connectors have outperformed traditional methods like boat spooling and butt-welding from a safety, operational and economical point of view.
Due to the reduction in weight, larger CT sizes have become available on older platforms as well. New CT applications that were previously considered unfeasible, like selective, high-rate acid fracing through CT, have been performed, extending the capabilities of CT interventions beyond previous logistical and technical limits. Being able to select the correct size of CT, with less dependency on offshore crane limits and weather has a fundamental impact on the usage of CT in the offshore industry.
Rather than discussing the spoolable CT connector itself, the primary intention of the paper is to re-view case histories that were performed during the last 5 years. Operational challenges that have been mastered, successes, failures and further developments are presented. A new CT reel configuration to simplify spoolable CT connector installation will be presented. The new applications made possible by this technology and their economic impact on the Norwegian CT market since year 2003 will be reviewed.
A web based system has been developed to improve workflow optimisation, collaboration and the communication of a business process. This new generation project management application greatly enhances the ability of an organisation to comply with external standards and implement consistent internal systems. It helps people of all levels of experience to share information across geographical and organisational boundaries, can reduce cycle or reactivation time and helps to implement controls such as stage gates. The user interface displays the workflow and current status of single or multiple projects with unparalleled clarity.
All companies have management systems or work processes, some more formal than others, to help maintain consistency and quality in their business delivery and to ensure compliance with corporate and regulatory requirements. There is a common need across industry sectors and disciplines to define a way of working and then ensuring that this "business process?? is used. Management systems may be inefficient or may even fail for a number of reasons, including lack of detail or too much detail, poorly defined requirements or inadequate information technology.
The simple but highly innovative web based system described in this paper was completed and implemented six months after coding began. An existing process had been mapped to the new software so users were immediately familiar with the task descriptions and terms used. The application delivered on its basic promise; improved process visibility, consistency and compliance with defined standards.
This paper contains a summary of the system attributes that led to a successful launch in Talisman Norway (TENAS) and suggests that a high degree of commonality exists between processes in different organisations. This paper will be of interest at all levels of an organisation - Managerial, Technical and Administrative.