bluuebunny/crossref_metadata_2025_split huggingface dataset:
Validation and Verification of Large-Bore Tubing Retrievable Safety Valves for Gas Wells
Authors: Thompson Grant R. 
Published: February 2015

This paper discusses validation and verification considerations for large-bore sub-surface safety valves, particularly with respect to use in natural gas completions producing high flow rates to 450 MMSCFD and beyond.
With natural gas wells, it is generally desirable from an economic standpoint to use larger production tubing than typically used for conventional oil wells. The larger sub-surface safety valves used in gas wells are exposed to unique conditions during operation. An estimate of the expected production rate of a given gas well is written into the statement of requirements for completion equipment. Validation and verification of the valve design to meet these requirements is a great challenge for equipment designers and test agencies, particularly for high flow rate analysis and testing. Only a small number of facilities have the capability to meet the volume and pressure requirements for testing the closure performance of large-bore safety valves against high gas flow rates.
Production gasses flowing through the tubing string encounter discontinuities in the form of stepped changes in diameter at each tubing connection. As these large-bore safety valves are in the full-open position, changes in the diameter from entry to exit are only slightly larger than those at the tubing connections. During closure, and especially closure while flowing, the transient state of the valve provides a significant discontinuity to the flow path in the immediate vicinity of the closure mechanism. Discussion of valve design utilizing various analysis models is provided to understand how these high rate flow characteristics affect valve performance.
In addition to unique analysis methods, these large-bore valves also require physical validation to ensure reliable performance in high gas flow rate conditions. Validation testing for these conditions is highly desirable and lends additional confidence in the performance of these products in emergency high flow rate scenarios. By including the proper design and testing protocols as shown in an actual case history, these large-bore valves capable of high flow rate applications are shown as fit for purpose in the most demanding of gas fields.
The Role of Seismic Inversion in Exploration and Development: Adding Value and Reducing Uncertainties
Authors: Rajput Sanjeev , Ring Michael 
Published: February 2015

Developing accurate and high resolution reservoir models imply integration of data from different sources in varying scales, which is one of the major challenges in reservoir characterization. Relatively low resolution of seismic data could only offer a structural model for the reservoir but its availability and areal coverage suggests that it has valuable information to constrain the reservoir model. This information could be extracted by the process of seismic inversion that transforms seismic data into a quantitative rock property, descriptive of the reservoir. In this study a novel intelligent seismic inversion workflow is presented to achieve a desirable correlation between low-frequency seismic signals, and the much higher frequency well log data with reducing uncertainties.
The proposed logical workflow consists of a systematic progression from well data analysis to rock physics modelling to seismic inversion and finally reservoir property estimation. The results reveals that optimization of seismic inversion workflow must be handled in unique manner. By using a series of simple examples to complicated case histories it will be demonstrated that significant benefits can be obtained by following an optimized workflow that is tailored to deal with the uncertainties that impact the end product.
It can be concluded that relative inversion should be performed first so that one should be crystal clear about what information can be extracted only from the seismic without bias from logs. The next step is absolute inversion which implies logs as geologic context and broadens the inversion band to establish the relation between log and seismic. At final stage one should consider more advanced techniques such as model base inversion, elastic inversion, simultaneous and geostatistical inversion. The ultimate goal is optimum reservoir characterization and management which leads to success and reduce uncertainties.
Permeability-Dependent Retention of Polymer in Heterogeneous Reservoirs
Authors: Choi B. , Lee K.S. , Yu K. 
Published: February 2015

Polymer retention occurring in porous media induces significant mobility reduction as well as poor sweep efficiency. In the heterogeneous reservoir, it is very complicated and difficult to analyze performance of polymer due to permeability-dependent retention. Among various mechanisms of retention, mechanical entrapment of polymer affects mainly the propagation of injected polymer solution by forming macromolecular polymer plugging into pore throats, especially occurring in low permeability zone. Besides, polymer adsorption contributes to mobility reduction and polymer retention. The influence of heterogeneity on polymer retention has been not investigated accurately in the reservoir scale and limited to experimental studies, even though both mechanisms are highly dependent on permeability. In this paper, extensive numerical simulations incorporating mathematical modeling on the retention mechanisms have been performed to examine polymer propagation and flow behavior at various heterogeneous reservoir models. All reservoir models have same average permeability and different Dykstra-Parsons' coefficients (VDP) to represent wide range of reservoir heterogeneity.
The results show the amount of polymer adsorption is at high level in low permeability zone. The mechanical entrapment also exhibits same trend with adsorption. Most of polymer retention is accumulated in the low permeability zone, which causes a substantial increase resistance factor in the area. After polymer flooding, total amount of polymer accumulated by retention in the reservoir with VDP=0.72 is 2.5 times more than that of homogeneous reservoir. Furthermore, flow path of polymer solution is restricted to only high permeability zone in the highly heterogeneous reservoir. Thus, the polymer propagates through small pores at a lower rate, giving very poor sweep and irregular propagation path. Sweep efficiency of polymer flooding in the case of VDP=0.72 is reduced about 33% compared to the case of VDP=0.14. This paper could be helpful for an accurate assessment of polymer retention during polymer floods in the heterogeneous reservoirs.
Comprehensive Rigsite Operations Surveillance for Better Drilling Efficiency
Authors: Mohamad Azlan , Mad Desa M Latif , Ismail Zulhilmi M. , Hj. Abu Talib Hj. Sa'aid Hazley , Kardani Ilen , Deshamduli Dintho , Rosli Azlesham , Hj. Salleh Intan Hairunissa 
Published: February 2015

Implementing total operational surveillance can provide a detailed statistical breakdown of each rig's activities within an operation, enabling operators to accurately measure operational efficiency and flagging potential downtime events. PETRONAS has embarked on a full scale rigsite since 2010 with the setting up of a comprehensive operations surveillance monitoring center (Smart DOMC). This paper describes the process and benefits of streaming down rigsite operational information and data on a real-time basis to the monitoring center.
The Smart DOMC has become a center of excellence for domestic knowledge sharing, exchanging information, as well as a database of best practices, systematic trouble shooting, applied technologies, and capturing lessons learned. Very soon, the Smart DOMC will monitor all PETRONAS Carigali operations worldwide, which will encompass almost all drilling operations including land jobs, offshore operations, deep water, high pressure/high-temperature (HP/HT), carbonate drilling and unconventional technologies. These complex operations must be monitored and supported with robust infrastructures and competent manpower within the monitoring center.
Operationally, high-resolution tools and sensors (surface and downhole) must be installed at the rig site for automatic data generation and transfer to the Smart DOMC by means of satellite. This information is segregated to produce reports related to wellbore integrity, formation evaluation, bottom hole assembly (BHA) performance, and drilling efficiency. Proprietary software is then used to transform digital data into presentable graphical formats for further evaluation and data storage.
Implementation of such engineering and data surveillance were implemented in recent drilling campaigns in the Angsi Field, Sumandak, Tangga Barat, and Sepat projects. USD millions were saved by eliminating potential non-productive time (NPT) events and implementing efficient decision making. Obtaining accurate statistical data from each rig's operations allowed drilling management to reduce the NPT to barely minimum i.e., less than 5%.
Using LWD Tools during Soil Boring Operation to Identify Offshore Geohazards
Authors: Kardani Ilen , Askar Mohd Azlan Shah , Bong Martin , Sidek Rosli , B Mokhtaza M. Haflan B , Muhamad Zakaria B , B Zubir Ahmad Bakri , Yun Thiam Yap 
Published: February 2015

Logging While Drilling (LWD) tools have been used in most drilling operations whether offshore or onshore, and from top holes all the way to total depth. This practice provides most of the information required for all stake holders of oil and gas reservoirs. The focus of this paper will be the use of LWD tools in soil boring operations which has never been done or recorded before.
Site investigation is the first step in gathering geotechnical information for evaluating soil integrity for activities such as pipeline installation, platform construction, jacket installation, or drilling rig positioning. A feasibility study is done by performing a series of in-situ (or lab) tests to help operators and drilling contractors identify any geohazards and prepare suitable mitigation plans. Failure to do so can lead to expensive incidents during subsequent operations such as shallow gas, jackup rig punch through, damage on the jacket, pipeline failures, shallow water flow, gas hydrates, and environmental pollution.
LWD tools in combination with standard soil boring investigation (coring, soil sampling, cone penetration test, etc.) provide comprehensive site survey information including rock types, gas identification, wellbore imaging, water saturation, shear measurement, wellbore stability, lithology, and fracture identification. More detailed information can be acquired by using nuclear tools or seismic while drilling but these are not recommended for soil boring operations. In addition, the operator will have continuous formation evaluation data in cases where the surface hole is driven by conductor pipe. (LWD tools cannot acquire data once the casing is set.)
Combining petrophysical, geophysical, and geotechnical data at the earliest stage lets operators prevent undesired events by clearly identifying geohazards, and then either mitigating the hazards or determining that the location is unsuitable for further operations.
The Effects of Initial Condition of Fracture Surfaces, Acid Spending and Acid Type on Conductivity of Acid Fracture
Authors: Al-Momin Ali , Zhu D. , Hill A.D. 
Published: February 2015

Predicating the conductivity of acid fracture is not possible using analytical or numerical models due to stochastic nature of acid reaction with rock and complex leak-off behavior of acid. Other alternatives are either empirical correlations or conducting experiments mimicking field treatments.
We adopted experimental approach considering scaling down of field conditions to laboratory scale by matching Reynold's number to represents flow along the facture and acid leak-off through fracture faces, and Pecelt number to represent acid transport to fracture walls. Experiments conducted comprise three stages: dynamic etching, surface characterization of etched cores and conductivity measurement.
One objective of this work is to understand mechanism through which conductivity is generated in acid fracturing treatment. Moreover, the effect of initial condition of fracture surfaces on conductivity was investigated to quantify the difference between rough-walled and smooth-walled fractures. Another area of interest is the variation of conductivity along the fracture due to acid spending. In previous works, experiments only represented fracture entrance of actual treatment neglecting that acid is spent along the fracture which affects conductivity. Therefore, to better predicate the performance of an acid fracture, experiments at different acid concentrations representing different positions along the fracture were conducted. We also investigate effect of contact time, acid system type and treatment temperature on conductivity using San Andres Dolomite cores.
Preliminary results showed that initial condition of fracture surface has a major influence on fracture conductivity where rough-walled fracture predicted higher conductivity by almost an order of magnitude compared to smooth-walled. And mechanism through which conductivity created is by smoothing peaks and valleys creating surfaces mismatch rather than creating asperities. Furthermore, results showed that acid spending does not necessarily cause a decrease in conductivity from entrance toward the tip of a fracture. Also, cross-linked acid is more effective in terms of dissolving rock and controlling fluid leak-off compared to linear gelled acid. Furthermore, more etching does not always translate to higher conductivity suggesting the existence of optimum contact time.
Results obtained provide new insights to better understand and predicate conductivity of acid fracture and suggest guidelines to optimize treatment design.
Integrated Optimisation for Surface and Sub Surface Towards Maximising Production
Authors: B Zainal Abidin Shahrul Azman , Bt Hussein Noorhidayah 
Published: February 2015

Conventionally a standalone topside process model can only achieve production increment of up to 1%. In order to achieve higher production increment, an integrated topside process and subsurface model is required. This modeling technique requires the integration of different modeling platforms for reservoir, wells, headers, topside facility, interconnecting pipelines between platforms and re-injection wells back to the reservoir. The main challenge is to develop a seamless interface communication between the different modeling platforms.
PETRONAS has developed the link and global optimization engine to achieve seamless communication between the various Integrated Optimization tools such as PROSPER, GAP, and OLGA and iCON for steady-state and dynamic environment through parametric run approach. This allows faster diagnostic and effective decisions making in determining the topside optimum operating conditions.
To date, this integrated surface and subsurface optimization approach has realized up to 5% production increase from several platforms in Sarawak Operations. This paper also discusses the current and future application of the integrated approach for PETRONAS Carigali Integrated Transient Network Modeling (ITNM) and Integrated Operation (IO) projects.
FPSOS for Deepwater Applications
Authors: Su Zhiyong , Luo Yong , Qi Xiaoliang , Xie Yi 
Published: February 2015

This paper addresses the design and challenges of FPSOs for deepwater applications. The building blocks of FPSOs of topsides, hull, turret, mooring and risers are reviewed and a design concept of FPSO for deepwater application in the South China Sea is configured. Especially, the turret configuration of the deepwater FPSO is proposed. Engineering analysis with regards to the system global performance, Turret loads design, mooring and riser designs and their impact to the turret and hull is conducted. The technical challenges facing the deepwater FPSO design in areas of turret loads, mooring and riser design, coupling effects between FPSO and moorings/risers are highlighted. In the deepwater application, the single point mooring system and the riser system design for the FPSO become the key issues in the project because both systems have to face new challenges, such as deep water depth, wild environments and high fluid pressure.
A case study of a specific FPSO design in 1500m water depth in the South China Sea environment is then presented. The paper concludes that even though the design of the deepwater FPSO in harsh environment conditions can be technically challenging, the FPSO concept is a versatile solution for the deepwater applications in the South China Sea.
The History of Hydrocarbon-Based Ultrafine Cement Slurry System for Water Shutoff in Offshore Mexico
Authors: Deolarte Carlos , Zepeda Rafael , Cancino Victor , Robles Fernando , Soriano Eduardo 
Published: February 2015

Excessive water production can detrimentally affect the profitability of hydrocarbon producing wells if not controlled properly. Water cut present in the oil stream coming from the wells producing in several of the offshore Mexico fields is an issue of critical importance because oil production is sent to exportation. In the beginning the operators didn't have water handling facilities, forcing operators to monitor wells with water cut as low as 60.0 %. Forced to control by decreasing the choke size, in some cases the operator can handle the water, but in many cases required shutting the well in completely causing a negative impact on the production of the fields. Two of the main drivers of excessive water production is the mature fields are the influx of water behind the casing and/or water flowing through the natural fractures of these carbonate reservoirs. This paper describes the best practices of using a selective hydrocarbon-based ultra-fine cement (UFC) slurry system to slow down water production in offshore Mexico wells.
The UFC slurry consists of ultra-fine cement with an average particle size of 2.5 μm, a surfactant, and a hydrocarbon carrier fluid (i.e. diesel). Because the slurry is hydrocarbon-based, it remains inactive when contacting an oil-producing zone. When the system contacts a water producing zone the slurry will remain mobile for an additional 20 to 30 minutes before beginning to set. The delayed setting of the cement slurry is ideal for placing the ultrafine cement slurry into water-bearing formation fractures some distance away from the wellbore. The slurry is designed to selectively shut off water flowing into the wellbore and is applicable up to 400°F (204°C).
This paper describes the successful best practices and mistakes of the implementation of the UFC slurry system in Offshore Mexico to seal off unwanted water flowing through natural fractures and/or behind the casing. A variety of case histories will be discussed in detail along with post-production numbers after the treatment. Up to date, more 100 UFC treatments have been performed in Southern Mexico
Maintaining Wellbore Integrity in Steam Injection Wells Using Fit for Purpose Cement Systems in Oman
Authors: Jain Bipin , Khattak Mohammad Arif , Mesa Alvaro Martin , Al Kalbani Sultan , Ahmed Junaid , Al Aghbari Salim , Qassabi Nabhan 
Published: February 2015

In Oman, certain fields contain heavy oil and recovery of this oil is done through steam injection, which leads to rapid heat-up of the cemented annulus to very high temperatures. Throughout the lifecycle of steam injection wells, stresses in the cement sheath induced by rapid temperature cycling, results in mechanical damage and ultimate failure of the cement sheath. Such failure leads to loss of steam down-hole and an increased amount of steam is required to extract the oil. This translates into higher energy costs for steam production. In extreme cases steam can be seen breaking through to the surface.
In Oman heavy oil reserves are found in naturally fractured limestone formations prone to severe losses while drilling. To ensure proper cement placement, systems with densities below 1,400 kg/m3 are required. In the past certain wells were cemented using foam cements with density close to that of water. Data collected from earlier steam injection drilling campaigns by PDO suggests that maintaining cement integrity is a key challenge. The issue is related to initially not being able to place the cement properly due to losses and subsequent degradation of set cement as it does not withstand the stresses created during steam injection process.
A recently developed specialized cement system was used to successfully cement one such well. The system was placed successfully using fibers based pill ahead of the slurry to cure the losses. Stresses created on the cement sheath during steam injection were simulated, mechanical and thermal properties of the cement system were optimized to prevent failure, and evaluation was performed for wellbore integrity. Excellent mechanical and thermal properties for a 1,400 kg/m3 slurry system showed no breakthrough of steam when exposed to multiple temperature cycles of up to 300 degC. Multiple wells in Oman have been cemented using this technology.
The current paper looks at various aspects of design, execution and evaluation of such cement systems.
Kinetic Hydrate Inhibition Performance of MEG in Under-Inhibition System: Reduction Opportunities of MEG Injection for Offshore Gas Field Developments
Authors: Kim Jakyung , Shin Kyuchul , Kim Juneyoung , Chang Daejun , Seo Yutaek , Chang Kwang Pil 
Published: February 2015

In offshore gas field development, mono-ethylene glycol (MEG) has been a robust choice for hydrate inhibition in subsea production systems and flowlines. Once hydrate blockage forms, considerable efforts and loss of production are inevitable to remediate the hydrate blockage. Therefore, the industry has been relying on the injection of considerable amount of MEG which is used to be over-estimated based on the worst operation condition: shut-in pressure, sea water temperature, and maximum water cut. However, during steady-state operation, the range of operation condition might be different from the worst condition and for shut-in condition; the sufficient cool down time for hydrate formation could be guaranteed with appropriate insulation. More thorough analysis is required using the multiphase flow simulator. Furthermore, recent studies suggest that MEG may have kinetic hydrate inhibition (KHI) performance. An under-inhibited system where an insufficient amount of THI is present might be possible to avoid hydrate blockage issues and to reduce the operating cost for the injection of large amount of MEG.
In this work, the evaluation of under-inhibited system is carried out to identify the possibility of hydrate blockage formation using multiphase flow simulation tool, OLGA, and accompanying hydrate kinetics experiments. The temperature and pressure profiles along with the liquid holdup are estimated during the steady-state and transient operation of offshore gas fields. The optimized concentration of MEG is calculated form the simulation results. Then the under-inhibition concept is evaluated from hydrate kinetics experiments to investigate possible reduction of MEG injection rate. The obtained results suggest that at least 30% of MEG injection can be reduced using the kinetic inhibition performance of MEG in under-inhibited system, which in turn increase economic feasibility of offshore gas fields. More advanced strategy to manage hydrate blockage in offshore field developments would be developed based on the optimization of the injection rate in under-inhibited system.