An opportunity to establish a certain level of confidence in the well models by analysing entire production history or even performing analysis in real time becomes a reality of today. This paper is intended to describe an engineering approach to the analysis that was tailored to the Al Shaheen field to better understand the well performance, gain confidence in the models and identify various well issues and opportunities.
The challenge of understanding how wells perform is always associated with comprehensive data mining and significant time spent on analysis and calculations. However the data available is always limited and often requires quite a few assumptions to be made by an engineer when building a representative and reliable well model.
All industry standard software packages utilise same or similar well-known concepts and types of analysis from simple equations to more comprehensive algorithms. These are like pieces of the puzzle that can be assembled together to help petroleum engineer to get an idea of how the well should perform in particular circumstances. The way petroleum engineers applying these concepts on daily basis may vary depending on the nature of the problem they are facing and the amount of data they have available. Quite often the fact that the model does not match the reality is used to invalidate existing data and an opportunity to understand that something is happening in the well that is not captured by the model is overlooked. Reasons for this may include an existence of a particular purpose of the well model, level of engineer’s experience, skills or imagination, lack of required data or at the end an inability to process the entire production data in an efficient way. The last becomes a real challenge on the fields with large amount of wells and extensive production history.
Synergy between adopted analysis and the technology has allowed engineers to gain a much better understanding of the well performance, identify various issues and opportunities and enabled them to keep focus on making decisions as to which wells to optimise and those to troubleshoot to maximise potential of the existing well stock.
It is irrefutable that subsea operation is one of the most critical operations for Oil & Gas industry. To meet the growing demand of energy in the coming years, upstream oil and gas industry will develop even marginal fields which would tie-back to existing infrastructure and require more complex subsea network. Subsea production monitoring, back allocation and fiscal allocation are an essential part of any field development, as inaccurate tracking of production will negatively impact management and recovery from a reservoir. The need for allocation is due to the fact of unavailable quality measurements of oil, gas, condensate and water produced and injected at all nodes in a subsea distribution system.
Contrary to easily monitored downstream onshore operation, subsea offshore operations cannot be easily monitored due to low reliability and high cost of subsea sensors. From industry experience, the currently available physical subsea flow meters, instrumentation and associated measurements are subject to deficiency, inconsistency and failure and results in low accuracy, and reliability. Due to these facts, there is a high demand for an alternative and accurate method of flow metering and condition monitoring for offshore operation and processing.
In the past few years the use of Virtual Flow Metering systems as a backup or validation system for MPFMs or Wet Gas Meters has become more common. There are various options available depending on the vendor; statistical analysis of measurements (steady state solution), high fidelity online flow simulation models (dynamic solution) or a mix of both (nodal analysis). While VFM is maturing it has not been fully accepted as a viable alternative to good physical metering.
Driving the dynamic model with real time measurements from the plant opens a new world of information for the operator in terms of model estimated data and enables him to take better decisions.
This paper will present a case study whereby a virtual flow metering system has fully replaced a multiphase flow meter for flow metering and allocation purposes.
Zha, X. (CNPC Drilling Research Institute/China University of Petroleum) | Lai, X. (CNPC Drilling Research Institute) | Zhao, X. (China University of Petroleum, Beijing) | Feng, J. (CNPC Drilling Research Institute) | Huang, W. (CNPC Drilling Research Institute) | Hui, B. (CNPC Drilling Research Institute)
Because of the four characteristics: low gas saturation, weak permeability, low reservoir pressure, and scarce resource abundance of CBM(coalbed methane)in China, the mining of CBM still has not good progress. The permeability of coal is usually less than 1mD (1mD=1×10-3μm2), and is general 0.001~0.1mD in high rank coal reservoirs which are existed widely in China. Under super low permeability conditions, production practice of coal bed adsorption methane is obviously different from conventional gas. Different permeability of coal bed generates a considerable variance in the optimum condition for drilling and well completion and development technology. Therefore, permeability determination plays a very important role in CBM development. When the coal core permeability is lower than 0.01mD, conventional permeability test method is difficult to obtain accurate permeability measurement values. A permeability measuring instrument basing on the principle of pressure oscillation is designed in view of this difficulty. The coal sample is first stabilized at certain pore pressure, then a specific sinusoidal pressure wave is applied to the upstream side of the sample, and the pressure response at the downstream side is recorded. Permeability is deduced from the attenuation and phase variation of the downstream signal as it pass through a sample under test. The diameter range of sample is 50±0.5mm, which can better react the heterogeneous reservoir characteristics. The instrument which is equipped with drilling fluid pollution system can simulate downhole conditions and changes in permeability by drilling fluid pollution. The lowest permeability could reach 1×10-7mD. The permeability of coal samples which are from Sihe /Shanxi Province, Wu’an /Hebei province and Gerick coal mine is measured with this instrument. Multiple experiment results show that the instrument can be in accordance with repeatability accuracy requirement of permeability test in super low permeability coal reservoir. The study provides the basis for the reserves evaluation and drilling and well completion technological design.
Trebolle, Ramiro (PETROFAC Malaysia) | Okamoto, Maruro (Petrofac Malaysia Ltd) | Chong, Emeline (Petrofac Malaysia) | Haddad, Sammy (Schlumberger) | Dashti, Rouhollah (Schlumberger) | Chouya, Smail (Schlumberger) | Wa, Wee Wei (Schlumberger)
Laminated formations especially in muddy environment during deposition time are known to be very challenging in terms of reservoir characterization and evaluation. Alternation of thin sand and mud layers in these types of rocks imposes natural anisotropy in the distribution of reservoir properties like porosity and permeability. This anisotropy has been proved to be a major control on fluid flow within the reservoir which is of paramount importance to understand and consider in reservoir development planning. The aim of this work is to integrate geological information derived from borehole images into interval pressure transient test (IPTT) interpretation to analyze and explain the complex flow behavior due to the combination of formation dipping and thin laminations. A wireline formation tester dual packer module was utilized in two offshore exploration wells to conduct an IPTT/miniDST in different formations including laminated muddy and sandy heterolithic formations. Several build up tests were performed to obtain valid reservoir pressure and permeability values. A good consistency was observed in the log-log diagnostic plot from these build up tests and the pressure derivative behavior suggests multiple possible reservoir scenarios in this complicated geological setting. A detailed study on borehole images and 3D near-wellbore geological model revealed the effects of slanted wellbore, laminated formation, highly oriented and dipping beds on the travel of pressure transient away from wellbore. With this geological information, a most representative reservoir model was able to be constructed to match the IPTT data to acquire the required reservoir parameters. This paper highlights the main challenges of formation characterization in laminated muddy and sandy heterolithic formations. Special emphasis was given to resolve significant problems encountered in pressure transient test interpretation in highly deviated wells. Slanted wellbore sections are typical in Malaysia’s offshore fields as the wells are drilled from offshore platform to intercept the formation at different angles, hence the pay zone and other petrophysical parameters are usually underestimated. Attempts are made to identify and classify these challenges, and recommendations are provided toward better resolution during interpretation.
Good understanding of the wind characteristics is essential in offshore structural design and operational activities. The short-term variability of wind is captured in design codes with prescribed forms for the wind spectrum and for the ratio of mean wind speed maxima for given durations to the one hour mean. Relationships are also prescribed for scaling these wind speeds between different elevations, essentially defining the wind profile in the turbulent boundary layer. All of these are based largely on measurements made in mid-latitude regions during extra-tropical storms or hurricanes; but these measurements will not be representative of the wind field during squalls, which are not stationary, and possibly not representative of the wind field during general monsoonal conditions. Several years of continuous recordings of wind speed and direction, sampled at 1Hz, at several South China Sea locations allow us to examine the short-term variability of wind in squalls and monsoonal conditions, and allow comparison with expressions given in design codes. We investigate the variability of the stationarity of the winds, the wind spectrum, the mean wind speed, and the wind profile, for the South China Sea measurements. The premise for the short-term variability prescriptions is that the wind field is stationary. Accordingly, we first report our evaluation of this assumption, and based on this, our evaluation of the relevance of the various prescriptions in the codes for describing short-term variability is developed.
Zhou, Shengjie (CNOOC China Limited, Zhanjiang Branch) | Li, Daquan (CNOOC China Ltd.-Zhanjiang) | Wang, Jianming (CNOOC China Ltd.-Zhanjiang) | Wang, Wenlong (CNOOC China Ltd.-Zhanjiang) | Chen, Dajiang (CNOOC China Ltd.-Zhanjiang) | Qiu, Chaopeng (CNOOC China Ltd.-Zhanjiang) | Liang, Siyin (CNOOC China Ltd.-Zhanjiang) | Jin, Tongjun (China Ocean Engineering Service Shanghai Company) | Zhou, Dongrong (China Ocean Engineering Service Shanghai Company) | Chen, Shi (Zhanjiang Nanhai West Oil Survey & Design Co.Ltd) | Yin, Yankun (Zhanjiang Nanhai West Oil Survey & Design Co.Ltd) | Deng, Xin (Zhanjiang Nanhai West Oil Survey & Design Co.Ltd)
The YC13-4 gas field in South China Sea is tied into the developed YC13-1 gas field existing facilities nearby. The CRA clad carbon steel gas riser and carbon steel umbilical protective riser are designed and together installed onto the existing jacket of YC13-1 gas field.
In order to ensure the welding quality of the CRA clad gas riser, avoid the high risks of simultaneous operations of production, hot works and installation, and taking into account of natural gas operational conditions of high temperature and high pressure around YC13-1 gas field existing platform, the installation method of dual-risers (gas riser and umbilical protective riser) together onto the existing jacket is used. The CRA clad gas riser and umbilical protective riser are designed, fabricated and precisely assembled on land forming dual-risers upper and lower parts together with fastening clamps based on measuring data of existing jacket correspondingly. The lower part is installed at first and then upper part. Each part is lifted, submerged in water, up-righted under the help of intentionally added buoyancy and then moved close to jacket by winch. The lower and upper parts are joined by bolted flange at last.
The installation of dual-risers together onto the existing jacket for YC13-4 gas field is actually completed within 10 days. This method avoids the close support from the existing platform and works efficiently.
High-resolution formation resistivity borehole images acquired in low-resistivity formations drilled with non-conductive mud systems can help in the analysis of structural dip, fracture systems, depositional environments, borehole stability, and net-pay identification in thinly bedded sequences. The high-resolution net-sand analysis from these resistivity borehole images_in conjunction with results from a multicomponent induction logging service_helps to determine an accurate net-pay, even in thinly bedded intervals.
Laminated formations frequently exhibit electrical anisotropy where resistivity measured perpendicular to the bedding (Rv) is significantly higher than resistivity measured parallel to the bedding (Rh). This occurs when high-resistivity sand layers are interspersed with low-resistivity shale layers. Analysis based on conventional resistivity tools will often bypass pay zones in thinly bedded sand-shale sequences. They measure horizontal (bed-parallel) resistivity, which is dominated by the low-resistivity shale laminae, not by the high-resistivity, hydrocarbon-bearing sand laminae. Average resistivity over these tools’ vertical resolution can be misleadingly low and computed water saturation pessimistically high. This is a major cause of “low-resistivity pay” in thinly bedded laminated formations.
In the Niger Delta where a comparison was made between the Water Saturation computed from Conventional Resistivity and that from Multi-Component Resistivity, there was a 30% reduction in the computed Water Saturation, which gave a substantial increase in the computed bulk volume hydrocarbon.
The multicomponent induction logging service is designed to efficiently and economically identify and quantify hydrocarbons in laminated, low-resistivity pay zones. It enables the determination of bed-parallel [RHorizontal (Rh)] and bed-normal [RVertical (Rv)] resistivities. These resistivity measurements, when utilized with the laminated sand-shale analysis and stable tensor petrophysical model, enable the determination of the true formation resistivities and water saturations, and thus lead to accurate identification, and quantification of hydrocarbons-in-place.
Active heating of subsea flowlines is an attractive solution for facing flow assurance issues related to always going deeper and longer, as well as more complex fluids and critical wellhead flowing conditions (pressure, temperature, flowrate) prone to pour point issues, hydrates and/or wax appearance risk.
Over the last 15 years, several active heating technologies have been developed and operated in order to significantly help solve flow assurance issues from the subsea wellheads up to the surface support facilities. These technologies have demonstrated to be very different in their design and operability (use of hot water, direct or indirect electrical heating) but also in their efficiency and cost.
In parallel with the development of heated flexible pipe designated IPB (Integrated Production Bundle) already used for field development in West Africa and Brazil as well as a rigid heated pipe-in-pipe technology, both using electrical heat trace cables, Technip has been involved in the design, construction and installation on several projects of all active heating technologies.
Based on this extensive knowledge and track-record, this paper describes and compares the working principle as well as the advantages and drawbacks of the different active heating technologies. This paper also identifies their limitations with regards to field application, i.e. length and water depth based on their actual development status.
On the basis of different generic case studies (shallow long tie-back, shallow in-field development, deep water tie-back and ultra-deep water in-field development), this paper finally reviews all the potential benefits the different active heating technologies can bring to a project and includes an economical comparison of these technologies.
Description of the Proposed Paper: Professor Ciobanu has developed a new concept for defining and evaluating the effective stresses from discontinuous rocks. Starting from this concept, he succeeded in building up mathematic models that calculate effective values of the stresses from rocks with a more accurate precision than the previous models. A part of these results have been recently presented in conferences where they have been appreciated by the audience.
In this paper the authors present their own results obtained by applying and customizing the models mentioned above for particular cases of undersea rocks, involved in different offshore activities.
Application: The information and results presented in this paper are useful and sometimes vital in evaluating of those deformations of undersea rocks that are important in case of some phenomena or technological operations, such as:
- compaction and subsidence of rocks that constitute the basement for different equipment that are supported on the seabed or ocean bed;
- hydraulic cracking, collapse or tightening in case of rocks that build up the offshore boreholes.
Results, Observations and Conclusions: Practically, in this abstract there are presented the following:
- a more developed model for the calculation of effective values of primary stresses of cohesive, porous rocks that build up reservoirs and undersea massive;
- the way that the geometric parameters of pores, pore pressure, pressure on the seabed or certain physic-mechanic constants of rocks influence effective stresses.
The observations and the conclusions in the abstract have been stated based on the results obtained by numeric analysis. The basic models of the above stated concept have been previously verified in laboratory test.
Significance of Subject Matter: The results from this paper are different from the others published in previous papers by the following elements:
- the new model of calculation of effective stresses - herein proposed, is based on a concept more precise and accurate than the other known models;
- the new introduced parameter for quantifying the form and pores distribution leads to unprecedented results and conclusions;
- reduces risk of using such calculation models in situations where they are not compatible.
Riserless dual gradient technology enables drilling tophole with weighted and engineered mud without discharge to sea. A Suction Module is run and installed subsea. This has a collection chamber where well returns are collected and diverted to a subsea mud pump. A Mud Return Line allows pumping or lifting the mud and cuttings back to surface.
In this way a “closed loop system” is established; mud and cuttings are collected at seafloor and returned to the shakers as with post-BOP drilling techniques. The technique eliminates discharges of mud and cuttings at seafloor and thereby a weighted and engineered mud system may be used to solve difficult drilling challenges, improve drilling efficiency and safety.
Selection of the technology is typically driven by its ability to impact drilling efficiency and safety, but in environmental sensitive areas also by the fact that discharges to sea can be reduced or totally eliminated. The technology also in many cases allows setting of the 20” casing deeper, eliminating an extra liner across problem zones.
A spin-off technology is Managed Pressure Cementing - MPC; Once the first surface casing is landed and circulation of cement starts, the subsea mud pump is used to control annulus pressure. The pressure is controlled during circulation of the cement slurry to avoid fracture and losses. Performance of the MPC system provides evidence of successful placement of the cement and that pressure develops as planned during the setting time.
RMR provides superior hole quality and MPC improves the quality of the cement job. In combination the structural integrity of the surface casings are improved.
The Paper will present the RMR and MPC technologies and some case histories.