Kumar, Amit (ExxonMobil Upstream Research Company) | Pacheco, Jorge (ExxonMobil Upstream Research Company) | Desai, Sanket (ExxonMobil Upstream Research Company) | Farooqui, Mohammad (RasGas Company Limited) | Morshidi, Leozarin (RasGas Company Limited) | Alkharaz, Hani (RasGas Company Limited)
In sour wet gas wells, an iron sulfide scale develops on the carbon steel production tubing wall which significantly retards the rate of metal loss due to internal corrosion. During late field life as reservoir pressure depletion occurs, high flow velocities in the wellbore generate high shear stresses on production tubing walls that can potentially damage the existing corrosion scale and expose the metal to higher corrosion rates. The modeling work done to estimate late field life shear stresses was reported in IPTC-17293-MS and presented in 2014 IPTC in Doha, Qatar. This paper discusses the findings from lab tests conducted in modified autoclaves and a customized flow loop to evaluate the stability of the iron sulfide coating at the predicted late life shear stresses.
The iron sulfide scale in the well tubulars was carefully characterized from historical scale composition data as well as analysis of freshly collected samples. This scale was then successfully generated in the lab under carefully controlled conditions. The stability of the generated scale was then tested in High Pressure High Temperature (HPHT) autoclaves and in a customized flow loop by subjecting it to a range of shear stresses. The results provide the first insights into stability of iron sulfide scale under different shear conditions.
Findings from this testing program are being utilized to: Develop effective erosion/corrosion management strategy Develop corrosion monitoring and wellbore integrity surveillance programs Define potential future constraints on well production rates Guide materials selection for future wells in the field
Develop effective erosion/corrosion management strategy
Develop corrosion monitoring and wellbore integrity surveillance programs
Define potential future constraints on well production rates
Guide materials selection for future wells in the field
Carbon Capture and Storage (CCS) is particularly attractive for the oil and gas industry due to the potential of Enhanced Oil Recovery (EOR). The presence of adequate well injectivity is identified as a prerequisite for CCS and CO2 EOR projects. Mineral precipitation in the vicinity of the well is suggested as a possible injectivity impairment mechanism. After mineral precipitation and formation dryout, continuous injection of CO2 into the formation could redistribute precipitates and alter injectivity. In this work, we investigated the effect of viscous force on precipitated minerals and the resulting consequences on permability and injectivity. The influence of supercritical CO2 injection rate, initial core permeability and saturating brine salinity were investigated. We observed that, injectivity impairment has a maximum immediately after mineral precipitation. Continuous injection of supercritical CO2 into the core after mineral precipitation is seen to reduce injectivity impairment induced by precipitated minerals. In most numerical and geochemical models, static injectivity impairment as a result of mineral precipitation is often assumed. Our findings suggest that injectivity remains dynamic throughout the injection process. Therefore, changes in CO2 injectivity after mineral precipitation could be complex to model and understanding of the processes is a good point to start.
The studied field, located offshore Sabah, Malaysia is composed of a succession of thick-bedded sand lobes, thin-bedded heterolithics and shale dominated mass transport deposits (MTDs). While the thinly bedded units contain significant hydrocarbon reserves, the distribution and continuity of sand bodies within these units cannot generally be derived from well data alone. Modern analogues suggest that these thin beds are likely composed of small scale sandy lobes embedded into a shale background. In order to better understand the vertical and lateral connectivity of these turbiditic elements, a numerical model integrating well data and seismic inversion results was built, constrained by a conceptual depositional model based on analogue data.
Multi-point geostatistics (MPS) were used as a platform to combine geological knowledge - in the form of a realistic training image, well measurements and geophysical trends. In order to reproduce observed facies proportions and architecture, the training images were generated using a novel user-guided, semi-automated workflow based on object-distance simulation. Reproducing the vertical heterogeneity of the model observed in thinly bedded units while retaining the lateral variability evidenced by seismic inversion was achieved by creating first set of facies probability cubes from the seismic inversion results using supervised neural-network estimation, then refining these probabilities by calibrating them to vertical proportion curves extracted from high-resolution facies logs. This technique enabled reproducing complex depositional patterns such as compensational stacking and hierarchical distribution of facies. It also allowed sedimentary bodies directly visible on the seismic inversion results to be integrated explicitly into the facies model. The simulated facies distribution was then used to constrain petrophysical property population, yielding detailed and realistic dynamic models.
While the presented approach is specifically tailored to the modeling of thinly bedded deep water environments, the innovative techniques proposed for generating a "photorealistic" training image and for integrating seismic-scale results with high resolution well data could also be used for representing a varied set of depositional settings.
Karst carbonate reservoir is playing more and more important role in current petroleum industry, and it is the same in study Tazhong area of middle Tarim basin and even the whole basin. Meanwhile, it is noted that paleogeomorphology of carbonate karst unconformity has obvious control on reservoir development and even hydrocarbon accumulation based on many case studies. Therefore, paleogeomorphology reconstruction is often very fundamental but indispensable study for exploration and production activities in such kind of reservoirs.
The study carbonate unconformity, i.e. the top of Yingshan formation of early Ordovician, typically occurs at burial depth of 5.2~6.5 km, which is almost the same as that of northern Tarim basin, such as Lungu area. However, there are more challenges here in the work of paleogeomorphology reconstruction for Tazhong area when compared to that for northern Tarim basin: 1) the study carbonate unconformity has much lower relief contrast on paleogeomorphologic micro-unit scale, 2) the overlying formation of Lianglitage is carbonate-dominated and contains many reef-shoal intervals (especially for the upper Lianglitage formation), and 3) the current structure of unconformity horizon seems much different from paleogeomorphology surface. These cause that the often-used methods fail, for example, the paleogeomorphology derived from the whole thickness of overlying Lianglitage formation will be distorted because of higher carbonate production rate at some topographic highs, which is different from a normal clastics case where thicker usually means lower and thinner means higher, like the situation in northern Tarim basin.
In order to improve the separation efficiency of the hydrocyclone, a new type of cyclone separator is proposed. According to computational fluid dynamics method, a new cyclone separator, coalescence-cyclone separator, is numerically simulated by Fluent software based on a co-rotating outflow reverse-cone hydrocyclone, and is compared with the co-rotating outflow reverse-cone hydrocyclone. Inlet flowrate, inter oil volume fraction and tangential outlet split ratio of the coalescence-cyclone separator were researched.
The Oil & Gas industry has an increasing demand for gas tight connections, particularly in deepwater applications such as in the Gulf of Mexico. These connections incorporate metal-to-metal seals and have been been motivated by wells requiring high-pressure completions/stimulations, drill stem testing, managed pressure/under-balanced drilling applications and wellbore cleanout assemblies. In response to customer requests, a new gas tight connection with a metal-to-metal rotary seal was developed. When developing this connection with high pressure gas tight capability, a no compromise approach was mandatory since safety and well integrity were primary concerns. This product can be utilized for both drilling and completion operations, so it represents a considerable cost saving due to improved operational efficiency.
This paper details the development and qualification of this new connection. In the development of this new connector Finite Element Analysis (FEA) was used, resulting in a product that is a hybridized version of a premium double shoulder connection and the gas tight connection from a drill-pipe-riser. The connection therefore provides the high pressure capability of premium casing or tubing connections coupled with the robustness and increased torsional strength associated with a double shoulder rotary connection. Qualification of the new product was performed on the most critical sizes and involved industry standard physical testing including make & break, overtorque, combined loading and fatigue testing. In fact, a staunch safety commitment has allowed it to provide one of the highest operating margins of any gas tight connection and is qualified to 30,000 psi internal pressure and 25,000 psi external pressure. The full qualification results are detailed and discussed in the following pages.
Al-Mohannadi, Muna (RasGas Company Limited) | Al-Kuwari, Ahmed (RasGas Company Limited) | Al-Mohannadi, Abdulaziz (RasGas Company Limited) | Al-Tayeb, Amna (RasGas Company Limited) | Al-Mannai, Ahmad (RasGas Company Limited) | Landis, Lester (RasGas Company Limited) | Nivarthi, Sriram (RasGas Company Limited) | Paez, Rachel
An important objective of a surveillance programme for a gas condensate reservoir is to accurately assess reservoir pressure depletion over time. However, partial-to-complete isolation of zones throughout such a reservoir complicates the collection and interpretation of reservoir pressures from pressure transient analyses alone. As a result, production logs are run to obtain zonal flow contributions to understand the status of zonal pressure depletion. Understanding these zonal contributions and their implications on zonal pressures requires an integrated knowledge of the geologic and operational controls on flow.
Integrated Geologic and Engineering Modeling Studies (iGEMS) is a workflow designed to provide this integration and, thereby, increase the value of surveillance data. iGEMS focuses on identifying well-level geologic and operation controls on flow. iGEMS uses an efficient process to rapidly create, run, and analyze single-well simulations that include the effects of boundary pressures and compositions inherent in the parent model.
A case study utilising the iGEMS workflow is covered in this paper. This case study provides a specific example of how iGEMS teams identify geologic and operational controls on reservoir performance and develop a better understanding of zonal pressure differences. iGEMS provides insights on these controls by using reservoir modeling as a tool to integrate surveillance data, well logs, core data and geologic observations. Understanding what is controlling flow in the reservoir helps engineers, geoscientists, and petrophysicists make better operating decisions to maximise reservoir performance.
In continuous pursuit of improving safety and operational standards in the drilling industry, Shell took a major step forward in the Middle East when Qatar Shell Services Company W.L.L. partnered with the local drilling contractor, Gulf Drilling International (GDI) in 2011 for operating the Al-Khor Jack up drilling rig.
During the course of this partnership, HSSE was identified as one of the main pillars to be recognized, developed, and reviewed continuously for compliance against key HSSE targets.
GDI the local drilling contractor in Qatar aspires to become one of the best in class drilling contractors. Qatar Shell is committed to assist GDI in achieving that goal by refining the safety leadership attributes within the GDI crew, developing the skills for effective use of HSSE tools, and focusing on performance and people.
Shell's vision in safety is "Goal Zero" which means having an incident free workplace. Qatar Shell's safety journey with GDI started with improving the safety culture in the workforce and focusing on preventing incidents. This was a crucial step in the beginning of the journey as the team had new staff, new rig and a new contract to cope with. In addition, the rig was supporting well testing operations and did not drill wells for the previous 2 years.
Qatar Shell has successfully implemented and contributed to both personal and process safety roadmaps on Al-Khor Rig by adopting, and continuously evolving the learnings and safety procedures that are implemented globally by Shell. A successful implementation of DROPS (Dropped Objects Prevention Scheme), Red Zone management, Hands Free working, and barrier ownership has had a significant impact on Shell operations globally. On the GDI Al Khor, the implementation of these safety drivers in the appraisal wells program led to a reduced number of incidents, comprising a total of 3 recordable incidents in 4 years of operations. In addition, to promote the safety culture onboard the reporting of unsafe STOP cards was encouraged.
On the rig, compliance continues to be measured, and leading HSSE indicators continue to be developed. The goals set by GDI and Qatar Shell will be achieved through continuous commitment and safety leadership. With the vision to constantly improve and uplift the safety culture on Al-Khor rig to become best in class, Qatar Shell's journey with GDI continues.
This paper presents the steps taken by PETRONAS Carigali (Turkmenistan) Sdn. Bhd., in undertaking the complex installation of a Gravity Based platform in the Caspian Sea. Its Gravity Based Structure (GBS) posed numerous installation challenges on top of the difficult and delicate constraints of the Caspian Sea – a combination that demanded creative solutions, design changes and tough decisions to realise this mega project.
Due to the scarcity of readily available resources in the Caspian Sea, the platform was designed to be self-installed without requiring a derrick barge. This was also one of the driving factors for the design of the substructure and superstructure. Hence, an ingenious design concept was opted for the platform - a self-installing 7,500 MT steel GBS with a conventional floatover topside. The GBS installation operation can be divided into several phases, namely Loadout, Dry Tow, Floatoff, Wet Tow, Lowering and Ballasting, Touchdown, Self-Penetration and Suction Penetration.
There are only a handful of steel GBS that have been successfully installed globally and this project, being the first GBS for PETRONAS, was by default a technical and operational challenge. The complexity increased as the GBS design especially its installation concept is unique and a first. With no prior experience of GBS installation in PETRONAS, this was indeed an unchartered territory for PETRONAS and more so for the project team. Through hard work, dedication, strategic decisions and sacrifices, PETRONAS is able to successfully deliver and install this one-of-a-kind state-of-the-art offshore facilities despite encountering numerous problems that challenge the very philosophy of the GBS installation concept.
The concept of self-installing GBS requires an innovative method for its offshore installation operation. Designed to be self-installed, the GBS’ installation philosophy undergone significant changes during the detail engineering, installation engineering and operation stages – changes deemed necessary to improve its installability and to suit onsite conditions. These changes include the enhancement through automation and barge mating, and Caspian winter sea state adaptability. Details of the changes and its reasoning will be highlighted in this paper.
SCAL measurements on core material from the Dunga Field in Kazakhstan clearly show two distributions of flow regimes, one with flow (good flow sand) and one without. If no precautions are taken the SOR and SWIR measurements are not representative of the reservoir. It is essential to map out the location and the nature of the high and low permeable zones in order to properly model the reservoir flow pattern. Visual inspection of the core reveals mm-scale bedding of darker and lighter facies. This paper describes an imaging study to address whether the bedding and the flow/saturation properties could be related and an attempt to quantify the good flow regime.
Scanning electron microscopy (SEM) images taken at a magnification of 10000 times and stitched together to show the area across the bedding apparent in core do not reveal anything other than homogeneously distributed grains, feldspar and clays. This result indicates that either the flow heterogeneities are not related to the laminations, or that the grain size does not play a role.
Computational tomography (CT) scanning was used in order to determine the density and spatial differences in the rock. The 3D tomograms were recorded in-house at an approximately 3 µm resolution and supplemented by experiments conducted at the European Synchrotron Radiation Facility (ESRF) where a resolution of 700 nm was achievable. Both of these tomograms clearly show structured, denser regions, which would likely be responsible for the observed flow heterogeneities. The CT results were combined with an automated mineralogy approach to determine the composition of the cores across the laminations. The primary focus of this experiment was to investigate whether the denser bands are related to certain mineralogy in the core sample. The QEMScan results do indicate that the dense bands are a result of clay rich sand laminations. This seems to constitute the regime of the porous media where the pore space cannot be resolved (the microporous regime).
The segmentation of the 3D data and following pore-connectivity analysis is used in an attempt to quantify the amount of good flow sand. The 3D data does not give rise to a successful prediction of the permeability which is indicating that even the good flow sand has permeability in the single-digit mD range. This is the case for both the 700 nm and 3 µm resolution datasets. There is a linear correlation between the connected porosity versus both the experimental results for SOR and SWIR. Thus, it may be possible to predict SOR and SWIR from CT measurements on plugs where SCAL measurements have not been conducted. It is, however, noted that the quantification of good flow sand (via the connected porosity) from the images does agree very well with our description of SWIR based on the good flow sand/poor flow sand combination. This is ascribed to the different length scales involved in the measurements and that fact that the limit is 3 µm for the images that we can readily treat. Getting the scales right will be a venue of future investigation.