Steam generation for the purposes of thermal recovery includes facilities to treat the water (produced water or fresh water), generate the steam, and transport it to the injection wells. A steamflood uses high-quality steam injected into an oil reservoir. The quality of steam is defined as the weight percent of steam in the vapor phase to the total weight of steam. The higher the steam quality, the more heat is carried by this steam. High-quality steam provides heat to reduce oil viscosity, which mobilizes and sweeps the crude to the producing wells.
The Prudhoe Bay field, located on the North Slope of Alaska, is the largest oil and gas field in North America. The main Permo-Triassic reservoir is a thick deltaic high-quality sandstone deposit about 500 ft thick with porosities of 15 to 30% BV and permeabilities ranging from 50 to 3,000 md. The field contains 20 109 bbl of oil overlain by a 35 Tcf gas cap. The oil averages 27.6 API gravity and has an original solution gas-oil ratio (GOR) of about 735 scf/STB. Under much of the oil column area, there is a 20- to 60-ft-thick tar mat located above the oil-water contact (OWC).
Africa (Sub-Sahara) Eni successfully completed a new production well in the Vandumbu field, 350 km northwest of Luanda and 130 km west of Soyo, in the West Hub of Block 15/06 offshore Angola. The VAN-102 well is being produced through the N'Goma FPSO and achieved initial production of 13,000 BOED. Production from this well and another well in the Mpungi field will bring Block 15/06 output to 170,000 BOED. Anglo African Oil & Gas encountered oil at the TLP-103C well at its Tilapia license offshore the Republic of Congo. The well intersected the targeted Djeno horizon, and wireline logging confirmed the presence of a 12-m oil column in the Djeno. Total started production from the ultra-deepwater Egina field in approximately 1600 m of water 150 km off the coast of Nigeria. At plateau, the field will produce 200,000 B/D.
The paper discusses a petrophysical evaluation method for complex tight gas formations in a mature and partially depleted gas condensate field in Oman, allowing a full petrophyscial evaluation as well as geomechanical modeling from a source-less petrophysical dataset, thus reducing operational data acquisition risk in partially depleted reservoirs without compromising on hydraulic fracturing design. The developed methodology includes the volume of shale estimation from correlation with Poisson's ratio for the feldspathic rich tight formation. This methodology was used in deep tight fields in Oman for more than 3 years in both vertical and highly deviated wells greatly reducing the risk, logging cost and complexity of operations.
Zheng, Ma Jia (Southwest petroleum University) | Liu, Xin (Schlumberger Technology Services, Chengdu, Ltd) | Zhao, Jian Ping (PetroChina Southwest Oil and Gas Field Company) | Qiu, Xun Xi (Sichuan Shale Gas Exploration and Development Company Ltd) | Fang, Jian (CCDC Geological Exploration & Development Research Institute) | Wang, Xiong Fei (Schlumberger Technology Services, Chengdu, Ltd) | Zhao, Jing Kai (Schlumberger Technology Services, Chengdu, Ltd) | Geng, Gan (Schlumberger Technology Services, Chengdu, Ltd)
The Sichuan Basin is the major target for shale gas exploration in China because of its rich gas stored in unexploited black shale with multiple bed series. National Shale Gas Exploitation Areas have been established since 2012, the proved geological shale gas reserves is 9210×108 m3 and 90.25×108m3 annually output has been achieved by the end of 2017.
The operating Sichuan Basin shale gas area located in the major compression tectonic experienced multiple geological structure movements in Earth history, showing characteristics of high steep structure with faults greatly developed. It's proven that the key factors in exploiting these targets are well acknowledged by the efforts to land and expose the lateral within the sweet zone. To successfully place lateral in reservoirs from geological perspective must overcome challenges of high uncertainty structure identification to make soft landing and maximize horizontal exposure in the sweet zone.
While it comes to shale gas reservoir, to pave the way for fracture operation and achieve good well completion, the drilling requires a relative gentle well path, keeping well path inclination with limitation, which requires to make azimuth turning to achieve this.
To ensure the optimum placement of the well in sweet zone, the integration of rotary steerable drilling system (RSS) with borehole images measurements in real-time have been implemented with the employment of well placement technique.
The borehole image portrays structural profile while drilling whilst the rotary steerable drilling system provides accurate trajectory control. With the help of borehole image and proactive log correlation, the trajectory can be landed precisely into desired best quality reservoir, although the formation dip and actual target depth become much different with geological prognosis. During the lateral section, the trajectory was also controlled effectively in the high-quality reservoir despite of structural variation and reservoir property change. Through use of Fit-For-Purpose solution it effectively improves drilling efficiency and positively impacts well production. These achievements subsequently help to optimize wells deployment plan and wells with longer lateral horizontal section were planned for greater predictable production rate.
Wang, GaoCheng (PetroChina Zhejiang Oilfield Company) | Zhao, Chunduan (Schlumberger) | Liang, Xing (PetroChina Zhejiang Oilfield Company) | Pan, Yuanwei (Schlumberger) | Li, Lin (PetroChina Zhejiang Oilfield Company) | Wang, Lizhi (Schlumberger) | Rui, Yun (PetroChina Zhejiang Oilfield Company) | Li, Qingshan (Schlumberger)
Huangjinba shale gas field is located at the south edge of the Sichuan Basin. It has very complex structures, in situ stresses and natural fracture corridors in comparison to adjacent areas in the Sichuan Basin. In recent drilling campaigns, drilling risks have caused some wells to fail in reaching their planned total depth, eventually failing to deliver cost-effective gas production. In order to mitigate drilling risks, e.g. mud loss, collapse, stuck, hang up, gas kick, effective drilling risk prediction is an urgent challenge to address. Integrating quantitative drilling risk prediction methods with qualitative methods could increase the prediction accuracy and avoid or mitigate the drilling risk during the well deployment stage.
In this project, multiple seismic attributes were used to predict natural fracture distributions which qualitatively indicated the locations where drilling risks were likely occur. Comprehensive geophysical characterization was performed to identify natural fracture zones and patterns, and their mechanisms were validated by analyzing regional geological and tectonic evolution.
Image log data was then integrated into the natural fracture distribution prediction from seismic to build a DFN (Discrete Fracture Network). This combination of the DFN predicted from seismic data plus quantitative image log information allowed improved accuracy in the prediction of drilling risks.
Following this, natural fracture stability was analyzed by building a 3D geomechanics model in order to predict drilling complex qualitatively. A full field 3D geomechanics model was built through integrating seismic, geological structure, log and core data. The 3D geomechanical model includes 3D anisotropic mechanical properties, 3D pore pressure, and the 3D in-situ stress field. Through leveraging measurements from an advanced sonic tool and core data, the anisotropy of the formation was captured at wellbores and propagated to 3D space guided by prestack seismic inversion data. 3D pore pressure prediction was conducted using seismic data and calibrated against pressure measurements, mud logging data, and flowback data. The discrete fracture network model, which represented multi-scale natural fracture systems, was integrated into the 3D geomechanical model during stress modeling to reflect the disturbance on the in-situ stress field by the presence of the natural fracture systems.
From these models, a drilling map which quantitatively indicated the depth where drilling risk such as mud loss, gas kick, etc. occurred was created along the well trajectory.
This paper presents the highlights and innovations in seismic multi-attributes analysis and full-field geomechanics modeling which integrate qualitative and quantitative methods for drilling risk prediction.
Oil and gas exploration in the deep-water areas have become a global hot spot. The deep-water area of the Baiyun sag in the Pearl River Mouth Basin is an important exploration target. The area is a typical deep-water hot basin of a wide range of geothermal gradients. Data from a single borehole shows a geothermal gradient from 4.0 to 6.64°C/100m. High geothermal field has an important control on the reservoir diagenesis, pore evolution and porosity-permeability trends. We analyzed sandstone samples from the ZhuJiang and ZhuHai Group, which were buried in the depth range between 500- and 4000m, and display similar composition and textures. The samples can provide insights into the evolution of reservoir diagenetic features under progressive burial process. We also analyzed sandstone samples frome EnPing Group. In general, the petrological composition was the main controlling factor of reservoir quality. The high geothermal field led to a rapid decrease in the porosity and permeability of deeply buried sandstones. Howerver, the EnPing Group, which has a deeper burial depth, shows good reservoir quality. Compared with the ZhuJiang Group and the ZhuHai Group sandstone, the EnPing Group sandstone is dominantly coarse sandstone with more quartz grains, minor feldspars and rock fragments. The EnPing Group is dominated by primary pores, which has a better porosity-permeability relationship than other groups. The deep-water of the Baiyun sag still has potential for exploration. In particular, EnPing Group sandstone reservoir may become a desirable goal in deep and ultra-deep exploration.
Yong, Rui (PetroChina Southwest Oil and Gas Company) | Zhuang, Xiangqi (Schlumberger) | Wu, Jianfa (PetroChina Southwest Oil and Gas Company) | Wen, Heng (Schlumberger) | Shi, Xuewen (PetroChina Southwest Oil and Gas Company)
Ning201 Longmaxi shale gas play is located on the southwest edge of Sichuan Basin. Block Ning201 surface is very mountainous and elevation range of drilling pads is between 400 meters and 1300 meters. The target layer of shale gas exploration and development is mainly the Wufeng Formation of the Ordovician system and the organic-rich shale interval of the Lower Longxixi Formation of the Silurian system. The total thickness is between 30m and 50m, and the overall buried depth is 2300~3200m. Field development of Ning201 shale gas play was geared up in 2014. During early appraisal phase before 2014, average testing results of wells were 10~15×104 m3/d. 7 vertical appraisal wells and 50 horizontal wells have been drilled and 38 horizontal wells among them have been put into production to evaluate optimized development strategy until middle of 2017. Changning area accomplished the construction of 15×108 m3/a production capacity. During production appraisal phase, different well spacing pads were configured, and some cross-well interference testing were performed to determine optimal spacing in Ning201 block. Only qualitatively understanding can be achieved with spontaneous field efforts and quantitative evaluation of long-term impacts on production with varying initial rate control and well spacing is still missing.
In this paper, an integrated modeling workflow was introduced to accurately simulate the production behavior of a representative shale gas well and to control production through a calibration model to optimize well spacing and maximize economic returns. The workflow begins with microseismic monitoring during shale gas well fracturing operations. Considering the fracturing pumping procedure, fluid and proppant volume and subsurface features, including formation, natural fractures and in-situ stresses, the heterogeneity of the hydraulic fracturing system propagation ensures that the simulated complex hydraulic fracturing network is in line with reality. After establishing a detailed hydraulic fracturing model, production performance is matched to history to better calibrate the conductivity of hydraulic fracture network in dynamic model as a relaible predicting tool.
Abdullatif, Osman (King Fahd University of Petroleum & Minerals) | Osman, Mutasim (King Fahd University of Petroleum & Minerals) | Yassin, Mohamed (King Fahd University of Petroleum & Minerals) | Makkawi, Mohamed (King Fahd University of Petroleum & Minerals) | Al-Farhan, Mohamed (King Fahd University of Petroleum & Minerals)
The Miocene deep sea turbidite sandstone of Burqan Formation is important hydrocarbon reservoir target in Midyan region, Red Sea, NW of Saudi Arabia. Excellently exposed outcrops of Burqan Formation in Midyan region provide good data to examine and evaluate the reservoir rocks. This study integrates field observations (sedimentologic, stratigraphic and structural) and measurements from outcrop analog of the turbidite sandstone to investigate and characterize the reservoir heterogeneity, quality and architecture. The methods and approach followed used sedimentologic and stratigraphic analysis based on vertical and lateral outcrop sections and photomosaic so as to reveal the vertical and lateral distribution of the lithofacies and their geometries at outcrop scale. Moreover, terrestrial laser scanning (LiDAR) was utilized in this study to capture outcrop meso to macroscopic sedimentologic and stratigraphic and structural features details (strata surfaces. geometry distribution, faults, fractures). We integrated field observations with laboratory analyses to characterize the microscopic sedimentologic heterogeneity of lithofacies, texture, composition and petrophysical properties of the turbidite sandstone.
The stratigraphic analysis shows variation in outcrops from proximal to distal parts, within 15 to 20 km traverse across the outcrops belt (west to east) of Burqan Formation. The sandstone body thickness varied between 2 – 4 m in the proximal parts and between 0.5 – 1 m distally. Also, these variations in thickness was associated with increasing of shale/sandstone ratio from proximal to distal parts. The sandstone bodies width revealed from outcrop mosaics extend laterally between 100 to over 150 m. The lithofacies consists of both matrix and clast supported conglomerates, pebbly sandstone and coarse to very coarse and medium grained, massive, trough and horizontally stratified sandstone. These facies were interbedded with siltstone, mudstone and shale. The sand bodies were vertically and laterally stacked in the proximal parts and decreases in the medial and distal parts, however, locally the shale and mudstone lithofacies interbeds and form baffle zones. The region is tectonically and structurally active, therefore, at outcrop scale the repeated tectonics and rifting in the region resulted in faulting, shearing and fracturing which added complexity to the turbidite sandstone reservoir architecture. Moreover, tectonic affected reservoir/seal relationship, reservoir continuity and distribution of inter-reservoir barriers and baffles.
The results of this high resolution outcrop analog study might provide information and data base on types and scales of geological heterogeneities and their impact on reservoir quality and architecture within the interwell spacing. Moreover, it might also provide guides for exploration and development and help in decision making to avoid risks under the complex geological setting in the Red Sea region and other hydrocarbon basins under similar geological setting.
Registration for the 2019 SPE Western Regional Meeting is now open. Please use the links above to register for the conference and make your hotel reservation. The 2019 SPE Western Regional Meeting promises to present an excellent opportunity to learn about the latest technical developments in areas of technology of significant interest to petroleum engineers at this time. Of course, our traditional areas of interest drilling and completion, formation evaluation, production, reservoir, facilities, health safety and the environment will provide the core of the program. Special areas of technology like heavy oil, thermal recovery, geothermal operations, and innovations will be part of the highlights of the program.