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Moradi, B. (Universiti Teknologi PETRONAS) | Awang, M. (Universiti Teknologi PETRONAS) | Sabil, K. M. (Universiti Teknologi PETRONAS) | Shoushtari, M. A. (Universiti Teknologi PETRONAS) | Moradi, P. (Shahid Chamran University) | Ajdari, Hamzeh (National Iranian Oil Company) | Shuker, M. T. (Universiti Teknologi PETRONAS)
Carbon dioxide injection in oil reservoirs is one of the main improved oil recovery methods; in addition, it is a useful method for the reduction of carbon dioxide in the atmosphere. Carbon dioxide generally exists in supercritical state in hydrocarbon reservoirs that are usually explored, but the temperature of some shallow reservoirs and reservoirs underlying permafrost is below the critical temperature of carbon dioxide which provides a unique opportunity for liquid carbon dioxide storage and the application of a novel enhanced oil recovery method. During this work, a compositional simulation study is conducted by a commercial compositional reservoir simulator to evaluate performance of the liquid carbon dioxide injection in a low temperature heterogeneous reservoir. The results show the oil recovery factor after 24 years of production, during liquid carbon dioxide injection is 14.79 %, which is 3.90 and 8.59 % higher than the water flooding strategy and natural depletion respectively. It also finds that the huge amount of CO2 is stored in the reservoir. This study further shows that the oil recovery increases by increasing the injection pressure and the injection of the liquid carbon dioxide in bottom of the reservoir.
Marine transportation of natural gas is critical for its monetization. Pipelines and liquefied natural gas (LNG) are the established technologies for offshore natural gas transportation, with compressed natural gas (CNG) recently proposed as an economically preferable alternative under certain conditions.
In previous work, we have delineated areas in a transportation-distance/gas-volume diagram, where each of the three transportation means mentioned above is economically most attractive. In general, once offshore pipelines are excluded because of water depth and sea-floor terrain limitations, CNG transportation is considered attractive compared to LNG for relatively small volumes and short distances. Until recently, the preferred material for proposed CNG containers has been metal, for reasons of simplicity, robustness, and development cost. However, metal CNG containers have a number of disadvantages, the most obvious of which is that the container itself may be several times heavier than the contained gas, and, consequently, such gas may be only a small fraction of the cargo carried by a loaded CNG ship.
Composite containers are an alternative to metal, with a number of advantages. First, composites are significantly lighter than metal. Second, composite containers can reach considerably higher containment pressures (hence capacity), while still maintaining lower weight compared to metal. Finally, composite containers are much less prone to corrosion, and as a result can contain gas that has not been fully treated. These facts make composite containers an attractive proposition and greatly increase the overall attractiveness of using CNG to monetize stranded gas.
We present here a thorough study using both metal and composite containers and optimized operating conditions, such as pressure and temperature, to explore the applicability of CNG for marine stranded gas transportation. A new map of the economic attractiveness of LNG and CNG as a function of transportation distance and gas volume is presented, showing a considerably expanded area of CNG preference over LNG.
This paper presents an innovative approach undertaken by a joint venture company of three ASEAN national oil companies in developing a marginal field, offshore Malaysia. This paper focuses on the development strategy, execution and challenges of the project in utilizing a jack up drilling rig to install a Light Weight Structure (LWS) platform.
The LWS platform is part of a Cluster Development Project, which is the second marginal field to be developed by the tripartite alliance in Malaysian waters. In view of the small reserves and sub-surface uncertainties, as well as many other prospective small fields in the block, light weight and relocatable facilities proved to be an attractive solution for early reserves monetization.
Through the development project, the company aims to pioneer marginal field projects in Malaysia by utilising ‘fit-for-purpose' design facilities supported on the LWS platform that was installed by a jack up drilling rig and connected to a Mobile Offshore Production Unit (MOPU). Additionally, the project was executed as a fast-track project with First Oil achieved ahead of schedule. The offshore installation was completed within three (3) months upon award of the Offshore Installation Contract. This has proved to be an effective execution by a small integrated project management team set-up by the unique tripartite alliance.
Kangean Energy Indonesia (KEI) on behalf of EMP Tbk, JAPEX and Mitsubishi Corporation drilled and completed five (5) Terang high-deliverability gas wells utilizing a Jackup rig in 2011. Terang field, as the Phase-1 of Terang, Sirasun and Batur (TSB) fields' gas development project was put into production in 2012. TSB fields are located at east of Surabaya and north of Bali Island with the water depth ranging from 300 ft to 750 ft. Terang field is located in the western part of the complex with the water depth of 300 ft.
The challenge of this project was to drill and complete subsea wells by a jackup rig which is equipped with only surface BOP. This is a new endeavor to perform subsea well completion using a jackup rig in Indonesia and finally it is a successful operation to drill and complete the five Terang wells using a long-leg jackup rig.
Terang field had been developed by drilling and completing five (5) subsea production wells. Special additional devices were designed and attached to the jackup rig to enable drilling the subsea wells as well as perform batch drilling easily. These are High Pressure (HP) drilling riser and Suspended Texas Deck (STD), which is an additional deck suspended from the rig frame.
The STD was designed and introduced to promote operational safety by supporting safer and practical installation of the surface BOP equipment and also yielded a time-saving by reducing the handling time of HP drilling riser. These added features had proven to reduce operations time when two-well batch-drilling was performed, the rig cantilever could skid in and out with HP drilling riser suspended without breaking out riser connections.
The base cost reduction had been accomplished by utilizing a jackup rig which daily rate is much lower than floater rigs, and the contribution of the additional features of HP drilling riser and STD combination had further optimized the cost. This experience had brought a major breakthrough in drilling operations in Indonesia and KEI believe that the drilling campaign had been executed successfully with a diligent planning and articulated drilling programs.
Suling, Wang (Northeast Petroleum University) | Tiejun, Zhou (Daqing Oilfield Company, Petrochina) | Yang, Gao (RIPED, Petrochina) | Ying, Long (Daqing Oilfield Company, Petrochina) | Yuning, Wang (RIPED, Petrochina)
In China, some old oil fields into the late stage of development, the wellbore fluid become complexity, and the production and the pump efficiency gradually decline, which lead to an increase in production costs. According to the statistics, the efficiency of 36.7% of the total wells are lower than 30%, By analyzing the main reason for the low efficiency of the pump and combined the status of oil well production, statistical analysis on the impact of system efficiency under different working conditions and establish a corresponding model. The model mainly analyses the impact of stroke number, the stroke, the pump diameter, the submergence depth and gas content on pump efficiency. According to the well structural characteristics, a geometric model of the downhole rod system is established and the finite element model is generated by unit discrete. Considering the boundary conditions of the contact boundary of the sucker rod and tubing, the frictional resistance between the sucker rod and well fluid, the frictional resistance between the plunger and the pump barrel and the process of loading and unloading of the oil column, the numerical solution technology is adopted, which can reproduce the state of deformation of the rod string in a stroke, and gain the indicator diagram of the down hole pump and the efficiency of the system the down hole rod. Selecting the test wells of the oil production plant in Daqing Oilfield to check the model, the results show the error of pump displacement is 0.7% and the error of rod efficiency is 7.8%. On the basis of this analysis, the different stroke, pump speed, dynamic liquid level and pump diameter impact on the rod efficiency is analyzed. The calculation results show: the rod efficiency decreases with the increase of stroke and pump speed, the rod efficiency increases with the increase of fluid level and pump diameter and when the product of the stroke and stroke number is a fixed value,high speed and low stroke is beneficial to improve the efficiency of rod.
The main reason of resulting in low system efficiency of pumping unit well is low system efficiency of downhole1, 2 with the oilfield exploitation getting into the middle and later periods. Working efficiency is affected by the change of pitshaft fluid flow properties, especially has a great influence upon the working state of rod string and pump. Thus, it's very important to research the efficiency 3-5 in order to improve the system efficiency of pumping system in the later periods.
The numerical modeling method is adopted to establish calculation models of the efficiency of sucker rod and pump separately in this article in order to consider the influence of well fluid properties on working condition of sucker rod and pump valve ball, it can reappear the working status in one stroke, obtain the main parameters of rod string and pump, and then get their efficiencies. The above models were checked by using the wells that was tested in Daqing Oilfield and the theory and method were proved to be correct.
Calculation model of sucker rod efficiency
According to the structural characteristics of sucker rod well pitshaft, the finite element model is established based on finite element theory 6-9, as shown in Figure 1. The sucker rod and tubing are dispersed by adopting spatial beam elements, contact elements are established on the corresponding nodes of rod string and tubing. The tested polished rod indicator diagram is used as wellhead boundary conditions of the rod string, the open of traveling valve and standing valve of the oil well pump are used as downhole boundary conditions.
In low permeability oilfield, normally fracturing is applied for production and the water injecting pressure is quite high. As most of the major oil reservoirs are flooded by water after fractured, the production rate is very low. With the oilfields further developed, the number of high water cut wells increased. How to further tap the remaining oil and enhance the oil recovery is becoming a big challenge to us currently. In Daqing low permeability oilfield, a pilot test of pressure plugging, water control and oil recovery of high water cut wells was conducted and achieved a good result. The test was including: 1) Further verified the understanding of well and reservoir selection and established the selection standard of the pressure block, water control and oil recovery technique for fractured reservoirs in low permeability oilfield. 2) Optimized field operation process of pressure block, water control and oil recovery. Compensator + K341-114 packer + fixed pressure valve + K341-114packer + ball seat was designed as the plugging string. Small diameter string was studied to repair casing damaged wells. 3) Optimized the chemical plugging agent and developed the fracturing technique of plugging the water cracks through compound water plugging. Production enhancement and water drop were observed through large scale field application.
Li, Qiaoyun (Research Institute of Petroleum Exploration and Development) | Wu, Shuhong (Research Inst. Petr. Expl/Dev) | Wang, Baohua (Research Institute of Petroleum Exploration and Development) | Li, Xiaobo (Research Institute of Petroleum Exploration and Development) | Li, Hua (Research Institute of Petroleum Exploration and Development) | Zhang, Jiqun (Research Institute of Petroleum Exploration and Development) | Meng, Lixin (Research Institute of Dagang Oilfield, PetroChina)
Reservoir numerical simulation, which interests a large amount of reservoir engineers, is an important tool in oilfield development researches. This paper introduces a new generation simulator, which can be used to simulate the traditional and pseudo-compositional reservoirs. This simulator adopts finite volume method, completely implicit time discretization technology (CITDT) and dynamic space discretization technology (DSDT). The multilevel preconditioner solver, which is applied in the simulator, can enhance the computation speed. In this paper, a mature heterogeneous water-flooding oilfield with 30a's development history is simulated by this simulator. In the course of development, there are 242 producers and injectors drilled, and the exploitation strata-series are adjusted frequently. Currently the reservoir has entered the "double high?? stage, more than 79% of recoverable reserves have been produced and the water-cut reaches to 90%. After history-matching and production prediction by this simulator, the results shows that this reservoir numerical simulator can be used to simulate the complex reservoirs with long development history and mounts of wells, and it can describe the production performance precisely. Moreover, the case study indicated that the new generation simulator is a fast and adaptable tool to simulate the complex reservoirs with large scale, which shows its high potentiality in industrial application.
In the search for hydrocarbons, fractured carbonate formation drilling presents significant challenges associated with fluid losses and well control. These challenges also include open-hole formation evaluation. As a result, cased-hole analyses including production logging presented an opportunity to achieve complete formation, pressure and fluid evaluations in these fractured carbonate reservoirs.
In this appraisal case study, it was crucial for the G&G team to evaluate zonal productivity, fluid type, and formation pressure to further manage uncertainties in reserves booking. The target reservoir, which consists of cycle IV and cycle II carbonates, is naturally fractured with significant predicted gas reserves and unknown water contact. The 2nd well in the field has been recently successfully drilled to TD with a combination of conventional drilling with LCM to treat partial losses, and unconventional drilling with Light Annular Material (LAM) and pumping seawater through the annulus when total losses were encountered.
Though drilling was successful in this hostile carbonate environment, the main objective to obtain pressure measurements suitable for gradient analysis in open-hole environment at balance condition has raised uncertainties in their technical validity. Nonetheless, due to high risk of gas migration from fractures, the well needed to be secured immediately right after successful drilling. It was cased with 7?? liner and cemented. This left the operator staging for cased-hole wireline production logging to close the evaluation gaps.
Cased-hole wireline production logging program was designed to help in providing a better understanding on the fluid type, density and zonal contribution. When production log results were combined with cement log evaluations, they revealed important information that helped with better understanding the source of produced fluids beyond the standard production log interpretation. Results also presented lessons learned for future wells to be drilled in similar environment. Field results, challenges and lessons learned will be presented in this work.
China has abundant organic-rich source rock shales which are prospective for commercial shale gas/oil development but still in the early phase of evaluation and testing. We analyzed petroleum source rock data published in nearly 400 Chinese language papers to construct a unique GIS data base of shale geologic and reservoir properties throughout the country. We then conducted a comprehensive assessment of the country's shale gas and shale oil resource potential. China's risked technically recoverable resources within high-graded prospective areas are estimated at 1,115 Tcf of shale gas and 32 BBO of shale oil resources (Table 1). Of the dozen onshore sedimentary basins that were assessed, the most prospective are Sichuan, Tarim, Junggar, and Songliao. One of the most intriguing prospects is liquids-rich Permian shale on the structurally simple northwest flank of the Junggar Basin. The Pingdiquan/Lucaogou lacustrine shale is about 250 m thick and 3,500 m deep here. TOC averages 5% and the shale is oil-prone (Ro 0.85%). The area is close to infrastructure.
The Sichuan Basin, industry's primary focus for shale gas, has multiple shale targets but also significant geologic challenges, such as numerous faults (some active), often steep dips, high tectonic stress, slow drilling in hard formations, and high H2S and CO2 in places. Tarim Basin shale targets are mostly too deep (>5 km) apart from uplifts where they may be thin with low TOC. The Songliao Basin has liquids-rich potential in over-pressured and naturally fractured Cretaceous lacustrine shales. However, China's shale oil deposits tend to be waxy and stored mainly in lacustrine-deposited shales, which may be clay-rich and less "frackable?? than the low-clay brittle marine shales productive in North America.
Alian, Sima Sheykh (Deleum Chemicals Sdn. Bhd.) | Singh, Kulwant (Deleum Chemicals Sdn Bhd) | Saidu Mohamed, Anwarudin (Deleum Chemicals Sdn Bhd) | Ismail, M. Zaki (PETRONAS Group Technical Solutions) | Anwar, Mona Liza (PETRONAS Group Technical Solutions)
Organic deposition predominantly in the near well bore and in production tubing can create serious oilfield problems such as flow restrictions, near wellbore damage, efficiency of crude processing units and etc. As the reservoir depleted over the time, the solid deposition can lead to a steep decline in productivity of wells. The deposition of organic solids is one of many flow assurance problems faced by operators in Malaysia. It has been observed that, after years of production, many fields in Malaysia are suffering from organic solid deposition problem. This phenomenon is predominantly caused by changes in temperature, pressure and composition/morphology of the crude oil over time. To perform organic deposit removal treatment and prevention in the well, the nature of the solid should be characterized. If the deposit sample is organic mainly, it is important to quantify the various organic fractions of the solid sample collected from the production facilities. This paper explains how SARA analysis was modified to detect not only Macro-crystalline waxes (Saturates), asphaltene, aromatics and resins but also micro-crystalline wax and naphthenates. The content of each of above component will affect the method of treatment and the chemical formulation to treat the well. By knowing the composition of the solid sample along with Crude's Colloidal instability index (CII), Pour point and Wax Appearance Temperature (WAT), a customized chemical formulation can be designed. Lab studies were performed on solid samples collected from several wells to detect the flow assurance related issues prior to design of chemical formulation. With the analysis of the production data, history matching, and etc, a customized chemical formulation was developed to treat the wells. The proposed chemical formulation consists of 2 specially designed pills which would be simultaneously injected to the wellbore, which generates heat and ester once comingles. The heat melts the deposits while the ester disperses the melted solid. The initial studies of the treatment showed promising results; moreover the field implementation was very successful and proven significant increase in production rate. This novel system that combines both thermal and physical energy, evidenced to work effectively for wide range of organic compositions. Implementation of this system made it possible to restart the production from those wells which were idle due to extensive organic deposits. This technique was also often used to rejuvenate the old wells with low production rate. This paper discusses the diagnostic process and successful implementation of the proposed treatment in several oil wells in Malaysia.