Successful production from unconventional reservoirs is made possible by horizontal drilling and reservoir stimulation through multistage hydraulic fracturing along the laterals. Although hydraulic fracturing techniques have been widely used for unconventional gas stimulation, a considerable percentage of perforations do not contribute to production. The objective of this study is to integrate the geomechanical, petrophysical and completion parameters to precisely design hydraulic fracture for better hydrocarbon production.
Reservoir characterization and optimizing completion parameters are essential for effective well design to improve staging and perforation placement. Challenges in the design of hydraulic fractures include the proper placement of fracturing ports, perforations, and location of isolation packers. The challenges are due to the large variability in fracture gradients, mechanical and reservoir properties, and petrophysical characteristics along the lateral.
Industry experience shows that injection pressures required to fracture the formation (fracture gradient, FG) often vary significantly along a well and that there can be intervals where the formation cannot be fractured successfully by fluid injection due to high in-situ stress.
Geomechanical and petrophysical evaluations providing rock anisotropy and anisotropic stress properties along the wellbore play a fundamental role in completion and hydraulic fracture design. The paper shows how geomechanical and petrophysical properties from open-hole logs and sonic anisotropy evaluations are integrated to compute reservoir quality (RQ) and completion quality (CQ). Intervals with similar properties are grouped to better understand and optimize hydraulic fracture design and operations. This optimization procedure has been applied in a borehole within a potential shale gas reservoir targeting the hot shale facies formation in Saudi Arabia.
Application of this technology resulted in successful completion with optimum fracture stages and perforation clusters positioning thereby improving the initial flow capacity of the well.
A mini drillstem test (DST) with a Wireline Formation Tester (WFT) tool was performed in a low-perm, unconsolidated gas reservoir in a shallow well in offshore Malaysia to obtain high quality gas samples and to determine main reservoir properties. Single probe WFT attempts were unsuccessful in the offset well because of tightness attributed to high silt content. Consequently, the mini-DST was run in open hole, rather than the normal full-bore DST, which was an option for reservoir characterization.
This paper describes a successful reservoir characterization using a mini-DST in an open hole in a shallow low permeability reservoir; it provides background information about the wireline formation tester jobs conducted in an offset well. The paper also addresses the design criteria for performing the mini-DST and delves into the factors that were considered for job planning and proper job performance.
The unconsolidated sand posed some challenges, including a significant risk of sand failure during pumpout. Conversely, the low permeability requires more drawdown to flow the tested interval. The paper also includes the steps undertaken to minimize this risk by analyzing real-time data.
Despite low permeability, a good radial flow was obtained and used to estimate reservoir properties by creating proper drawdown. The high mobility of the low pressure gas in the reservoir compensated for the reservoir tightness. Although the radius of investigation in a relatively short buildup is not sufficiently high, it can still assist in reservoir characterization for development purposes with the integration of core, petrophysical, and DST data.
The paper also demonstrates the contribution of proper job planning and real-time monitoring to overcome operational problems expected while performing mini DSTs in low permeability and unconsolidated reservoirs, and describes methods for addressing those problems.
For the past decade, biogenic gas production from the offshore Gulf of Moattama has significantly contributed to both the domestic and international gas market in this region. And yet, despite success in exploring for biogenic gas, our understanding of how these generative and trapping systems work, to some extent, remains a mystery.
The primary goal of our study has been to unlock the mysteries of biogenic gas generation through a review of available literature and a detailed analysis of the geology and hydrocarbon occurrence in PTTEP's Zawtika Field.
Our study began with a detailed literature review in order to develop an understanding of the fundamental mechanisms of biogenic gas generation. We realised at this point that while biogenic gas generation is a common phenomenon; trapping of such gas in commercial quantities is unusual.
Through a process of intensive lab analysis of hydrocarbons and sediments, the geochemical properties of hydrocarbon gas and potential biogenic source rocks were determined. 1D burial history modeling applying biogenic gas kinetics was conducted to determine the key parameters contributing to the Zawtika Field success case. Success case analysis outputs integrated with latest literature findings has resulted in formulation of the recipe for biogenic gas generation and accumulation.
Depositional setting appears very important in the generation and trapping of significant volumes of biogenic gas. The series of progradational packages deposited within the Ayeyarwady Delta are instrumental in establishing the source-reservoir system hosting such biogenic gas deposits. These sedimentary fluctuations dictate change in lithological character resulting in coarsening upward sediment cycles.
Extremely high deposition rates are calculated for sediments deposited through Pliocene to recent times, commonly greater than 1,000m to 2,000m/million years. Such high deposition rates are instrumental in providing the sediment overburden that allows sealing of such biogenic systems.
The Zawtika field is situated west of the termination of the Sagaing and Mergui fault systems creating NE-SW trending splays at the end of the Moattama Basin. Within this specific depositional setting, post-oxic depositional environment conditions are required. This environment of deposition is initially oxic where high sulphate content in water in the depositional system inhibits biogenic methane generation.
Post burial, reduction of sulphate to few ppm levels provides a suitable environment for biogenic methane generation. Rate of removal of sulphate vs. depositional rate will have a significant impact on depth at which biogenic gas generation occurs and therefore possibility of trapping.
Low sediment water interface temperature (SWIT) and geothermal gradient/heat flow regime are required to place the biogenic gas generation window as deep as possible. Such is required so that generation occurs for as long as possible providing time for trap formation and sealing.
Subsurface geothermal gradient or heat flow less than 3.5°C/100m and 50mW/m2 respectively is likely necessary. Bio-gas generation window depth range of between 500m to 2,000m is considered typical with generation window lengths around 1 to 1.5 million years.
Continuous delivery of humic, land derived organic matter into the depositional setting is essential. However, provision of high amounts of high quality organic matter (High Hydrogen Index (HI)) is not required for the generation process.
It appears that methane generating micro-organisms are capable of metabolising organic matter with HI as low as 50, though, HI greater than 100 to 150 appears advantageous. Typical amounts of organic matter in such sediments range from as low as 0.5 to 1%wt.
The results of our study have clearly delineated the geological and geochemical parameters that have primary influence on the successful generation and trapping of biogenic gas in the offshore Gulf of Moattama.
From this we have been able to formulate a specific biogenic gas risking index that allows us to more effectively explore for biogenic gas in this and similar geological settings. With this knowledge and methodology in mind, we consider that PTTEP is positioned as a leader in ongoing exploration for biogenic gas in S.E. Asian and other biogenic gas prone basins.
In this paper, we report the results of the investigations on the effects of sodium hydroxide (NaOH) concentration and different ratio of silicate to hydroxide on the density, rheology and compressive strength of geopolymer cement system used in oil well. Different ratios of Class F fly ash is mixed with different ratios of sodium silicate to sodium hydroxide ratio (2.5, 1, 0.5 and 0.25) to produce different geopolymer slurry densities and dispersant is added to control the rheological properties of the system. The NaOH solution was prepared by diluting NaOH pellets with distilled water according to the specified molarity (8, 10, 12 and 14 M). The solution was then mixed with sodium silicate to form the alkaline solution. Class F fly ash were added to the reactive to form homogeneous mixture, which was tested for its density and rheological properties at surface temperature. The mixture was placed in a 50 mm mould and cured at 930C and 3000 psia for 24 hours and the cubes were tested for destructive compressive strength. The results showed that as the concentration of sodium hydroxide increases, the density of the geopolymer cement increases. There was no significant variation on the density of the geopolymer cement. Also, as the ratio of silicate/hydroxide increases, the viscosity of the slurry increases and the workability of the geopolymer cement become poorer. Furthermore, the compressive strength increases as the NaOH molarity increases however when it reaches 14M, the adverse effect to the strength development was observed.
There is an increasing trend in the oil and gas industry for the use of Enhanced Oil Recovery (EOR) techniques to improve the oil recovery from the reservoirs. The industry is well established to manage the hazards associated with hydrocarbon liquids and gases. However, polymer powder, used for Chemical EOR, presents a new set of hazards that needs to be incorporated into the HSE design of these facilities. This paper presents the main HSE design aspects to be addressed for the management of the process safety, environmental and personnel safety hazards introduced by polymer EOR facilities in the oil and gas industry.
Total has conducted a number of Chemical EOR studies and implemented pilot plants, with an aim to developing full oil fields based on polymer flooding of the reservoirs. A comprehensive review of these polymer projects has been carried out and the HSE lessons learnt have been assessed. Information from polymer suppliers has also been reviewed, supported by an extensive literature review of the HSE requirements and standards for other powder handling industries. The review focused on the HSE design aspects for those polymer EOR projects that use powder as the source material.
Hazards related to the handling of powder based products are effectively managed in other industries and documentation exists to guide designers on the requirements for managing these hazards in their processes. The use of polymer powder is not new to the oil and gas industry, however, very little guidance exists, to account for this hazard as part of the HSE design of the oil and gas facility, as it is less understood compared to the hazards presented by flammable oil and gases. An HSE guideline has been prepared to enable a better understanding of the hazards of using polymer powder in EOR facilities. The guideline serves as a bridge to facilitate the incorporation of this new hazard into an already established safety design management process. This paper presents the main HSE design aspects from this guidance document and addresses key areas such as flammability and dust explosion; area classification and ignition control; drainage and spill containment. The personnel safety requirements to protect the plant operators are also addressed.
Ozasa, Hiroaki (IHI Corporation) | Sato, Fumio (IHI Corporation) | Asakawa, Eiichi (JGI Corporation) | Murakami, Fumitoshi (JGI Corporation) | Jamali Hondori, Ehsan (JGI Corporation) | Takekawa, Junichi (Kyoto University) | Mikada, Hitoshi (Kyoto University)
We developed a towed marine seismic vibrator (MSV) as a new type marine seismic source that employed the hydraulic servo system for the controllability both in phase and in amplitude of the signal being emitted. MSV could mitigate a risk of the impact to the marine environment while satisfying the necessary condition of seismic sources and could enable shear wave analysis in the marine environment to improve the situation of marine seismic data acquisition. We conducted a sea trial to acquire seismic reflection data using a downsized MSV and a streamer cable above the seafloor where a cabled seismic observatory has been deployed. A series of controlled chirp signals was generated by MSV. The sea trial showed that penetration of seismic signals generated by the downsized MSV was comparable to that by an airgun of 480 cu-inch with a slight inferior signal-to-noise ratio. We could observe the improvement in the penetration of seismic signals for the downsized MSV towed deeper that is preferable to generate shear waves. Finally, we could observe that the amplitude of shear waves, which are reflected back from the subseafloor structure, is acquired by the horizontal components of a seafloor installed seismometer.
North Serayu basin is Java Tertiary sedimentary basins that is formed due to back arc basin and the sedimentary fills was begun in Eocene. The sediments ranged from terrestrial environment until the deep marine controlled by gliding tectonic. Oil seepages are found in some areas such as Karangkobar, Majalengka, Suruh, Klantung, Sodjomerto, and etc. This research was conducted with the aim of revealing the existence of hydrocarbons in North Srayu basin and its petroleum systems.
This study focused on surface manifestation, stratigraphic cross-section measurement, and analysis of the geological structures to determine subsurface. In addition, petrographic and geochemical analysis of rock and oil samples to determine chemical and physical properties. Measuring stratigraphy at several places in Kali Tulis, Kali Worawari and Kali Desel which located in Banjarnegara, Indonesia. Geochemical analysis of rock samples of Totogan and Worawari Formation, oil seepage samples in Klantung and Karangkobar to provide the value of carbon content, and correlating the characteristic of oil and rocks. AMT measurements in Cipluk Field with to determine the subsurface condition and petroleum system hypothesis.
Based on the measuring stratigraphy at several places in Kali Tulis, Kali Worawari which located in Banjarnegara composed by Worowari Formation which deposited on shallow marine environment and Kali Desel composed by Rambatan Formation which deposited on the slope of deep marine environment with turbidity system. Geochemical analysis of rock samples of Totogan and Worawari Formation has a TOC value of 1,42% with Tmax 405 °C and Rambatan Formation TOC value is 0.99%, Tmax 449 ° C, classified as Type III kerogen. Oil seepage samples TOC value is 1.3%, type III kerogen and considered quitely mature. AMT measurements in Cipluk Field showed two characters of resistivity, resistivity >1000 ohm meter indicate homogeneous folds, interpreted as Merawu and Penyatan Formation, resistivity <1000 ohm meter interpreted as Banyak, Cipluk and Kalibiuk Formation (
This research objective was to provide the new information about the North-Srayu Basin petroleum system enigma. Previous publication explained the abundant oil seepages in North-Srayu area, the potential source rock, and the potential petroleum system, but none of them explained about the geochemical analysis and conducted it with structural geology. This Paper collect all of the interpretation before and provide the best possibility of North-Srayu Basin petroleum system.
Li, Junjian (China University of Petroleum) | Jiang, Hanqiao (China University of Petroleum) | Liang, Bin (China University of Petroleum) | Zhou, Daiyu (Research Institute of Exploration and Development of Tarim Oilfield Company, Petrochina) | Ding, Shuaiwei (State Key Laboratory of Continental Dynamics, Northwest University) | Gong, Changcheng (China University of Petroleum) | Zhao, Lijun (China University of Petroleum)
Water injection is essential during secondary recovery process. For multi-layer reservoir, determining the water absorbing capacity of stratification is a necessary step when we investigate the reservoir's production status and analyze the distribution of remaining oil. It is also the precondition of reasonable measures to boost the production, and to improve the ultimate recovery. In view of the reservoir actual situation is multitudinous, such as water is injected at the bottom while the upper produces, and insulation between layer and layer is very poor which can lead to Interlayer channeling, conventional reservoir engineering methods have been unable to effectively forecast recovery performances. This paper set up a methodology of injection allocation in multi-layers water flooding reservoir with support vector machine (SVM) as the core. Because of the credibility of injection profile and liquid producing profile is the highest of all the materials, the method sets the injection profile data and fluid producing profile as the goal, the permeability, reservoir thickness, injection-production well spacing and injection speed and liquid producing as influencing factors, building support vector, then we establish forecasting model, and allocate the water injection rate to each layer. By comparing the injection profile data which is not involved in the prediction process, we found that the prediction of the support vector machine (SVM) method is close and practical, with high credibility. This paper also compared the results with numerical simulation results of commercial numerical simulation software. It is can be found that the method can accurately reveal the inherent law of oilfield development; it has good adaptability and sufficient accuracy. As the forecasting process taking too long, this paper gives the optimization of SVM algorithm. Due to the parameter optimization process of conventional SVM algorithm carried out by searching grid one by one, it ashows these characteristics: low efficiency, large memory overhead. In this paper, we replace the grid searching parameter optimization process by genetic algorithm in the process of machine learning, Results show that the computation time can be reduced more than 70%.
Conductor jetting has been the preferred installation method for deepwater drilling. This type of installation depends on the skin friction between the conductor and the formation, making axial load capacity the critical success factor. Failure of axial load resistance causes well subsidence, incurring high cost in a deepwater environment. In principle, a longer conductor length gives higher axial capacity.
The PSC Company has drilled deepwater wells in East Malaysia and plans to drill more wells in the future. The conductor was designed using the same parameters as the nearby fields and the historical data. In addition, third-party companies normally perform conductor analyses based on the Gulf of Mexico soil set-up rate, which is not similar to East Malaysia. These practices have inadequate theoretical support and could lead to failure.
The paper objective is to analyse the conductor length requirement for East Malaysia with The PSC Company's planned conductor. The analysis includes the conductor length requirements for different well parameters.
The soil profile was derived from the nearby field soil-boring data and previous well parameters to obtain the soil set-up curve. The soil profile was matched with various parameters to analyse the required conductor length. The result describes the significant effect of conductor and jetting bottom hole assembly weight. Higher weight gives more weight on bit, providing high immediate capacity and requiring a shorter conductor. In addition, setting long 20" casing imposes a higher load that requires a longer conductor. However, PAD mud weight and duration before land weight on the conductor do not provide a significant effect. Moreover, other conductor specifications that may be run in the future were analysed, showing the same tendency, where a heavier conductor requires a longer conductor.
This analytical method can be recalibrated for other conductor configurations in the future.
The information contained herein is provided with the understanding that the COMPANY makes no warranties, either expressed or implied, concerning the accuracy, completeness, reliability, or suitability of the information.
In mature gas wells which are suffering from liquid loading, foamer injection is employed to mitigate the liquid loading and increase the stable gas production. Evaluation of the foamers performance and their chemical stability prior to their injection in the wells is of great importance. For this purpose, laboratory tests are performed to give an indication on the foamers performance. In this study, we focus on the effect of hydrocarbon fractions (condensate/brine ratio) and temperature (up to 120 °C) on the foamer performance in laboratory tests. A modified version of the Bikerman gas sparging setup was designed to allow for tests at higher pressures (up to 15 barg) and temperatures (up to 150 °C), compared to the currently available test setups. Three tests were performed to quantify the foamer performance; foam buildup, collapse and liquid carryover tests. The results indicated that higher hydrocarbon fraction significantly reduces the foam formation rate and liquid unloading capabilities. The current work highlights the importance of using a representative brine-hydrocarbon ratio for foamer evaluation tests. Additionally, on the effect of temperature, three different foamers were studied and the results showed a significant negative influence of high temperature on the foamer performance. It was observed that the effect of temperature on foamer performance is surfactant dependent. Therefore, it is essential to evaluate foamers in the laboratory tests at the temperatures as close as possible to the field (downhole) temperature.