Maintaining a stable borehole and optimizing drilling are still considered to be vital practice for the success of any hydrocarbon field development and planning. The present study deliberates a case study on the estimation of pore pressure and fracture gradient for the recently decommissioned Volve oil field at the North Sea. High resolution geophysical logs drilled through the reservoir formation of the studied field have been used to estimate the overburden, pore pressure, and fracture pressure. The well-known Eaton’s method and Matthews-Kelly’s tools were used for the estimation of pore pressure and fracture gradient, respectively. Estimated outputs were calibrated and validated with the available direct downhole measurements (formation pressure measurements, LOT/FIT). Further, shear failure gradient has been calculated using Mohr-Coulomb rock failure criterion to understand the wellbore stability issues in the studied field. Largely, the pore pressure in the reservoir formation is hydrostatic in nature, except the lower Cretaceous to upper Jurassic shales, which were found to be associated with mild overpressure regimes. This study is an attempt to assess the in-situ stress system of the Volve field if CO2 is injected for geological storage in near future.
Si, Xueqiang (Petrochina Hangzhou Research Institute of Geology) | Xu, Yang (Petrochina Hangzhou Research Institute of Geology) | Wang, Xin (Petrochina Hangzhou Research Institute of Geology) | Guo, Huajun (Petrochina Hangzhou Research Institute of Geology) | Li, Yazhe (Petrochina Hangzhou Research Institute of Geology) | Shan, Xiang (Petrochina Hangzhou Research Institute of Geology)
Sandstone can be divided into many types with reference to permeability and porosity. Some scholars and researchers have established criteria to classify tight sandstone by using porosity and permeability. Sandstone with permeability less than 1mD and porosity less than 10% could be called tight sandstone. Exploration and development of tight sandstone gas has become a hot spot of oil and gas exploration (Dai J. et al., 2002) in China. Quite recently, tight sandstone gas reservoirs of different scales have been discovered in the middle-lower Jurassic of Taibei Sag in Turpan-Hami Basin. The purposes of this paperare to analyze the texture and composition of the middle-lower Jurassic tight sandstones, investigate diagenesis type and reveal the influence of diagenesis on reservoir quality.
Yu, Hongyan (State Key Laboratory of Continental Dynamics) | Li, Xiaolong (Department of Geology, Northwest University) | Wang, Zhenliang (State Key Laboratory of Continental Dynamics) | Rezaee, Reza (Department of Geology, Northwest University) | Gan, Litao (Northwest University)
Abundant shale oil and gas resources have been discovered in the Zhangjiatan shale of the Yanchang formation in ordos basin in recent years. Zhangjiatan shale is a typical lacustrine shale, which is different from Marine shale in physical properties. Most previous research has focused on Marine shale. In order to understand the rock mechanical properties of Zhangjiatan shale, we conducted dynamic and static elastic properties experiments. We selected argillaceous shale and silty laminae shale in Zhangjiatan shale as samples. In order to obtain the static Young's modulus and Poisson's ratio, we use the triaxial pressure test. We use the dipole log to measure the acoustic velocity down the hole, and then we calculate the dynamic Young's modulus and Poisson's ratio of the sample based on acoustic velocity. Young's modulus of argillaceous shale is slightly smaller than that of silty laminae shale and the Poisson's ratio of argillaceous shale is also smaller than that of silty laminae shale. The brittleness of argillaceous shale are greater than that of silty laminae shale, as a result, argillaceous shale is much easier fracturing under pressure. We plotted the cross-plot of RCS, elastic properties and TOC and reached a conclusion that the mass ratio of clay to quartz and feldspar determined the brittleness and deformability of rock, while organic matters also affected the elastic properties of rock. Therefore, the elastic properties of shale are not controlled by a single factor, instead of multiple factors.
Alcantara, Ricardo (PEMEX E&P) | Santiago, Luis Humberto (PEMEX E&P) | Fuentes, Gorgonio (IMP) | Garcia, Hugo (IMP) | Romero, Pablo (IMP) | López, Pedro (IMP) | Angulo, Blanca (IMP) | Martinez, Maria Isabel (IMP)
The Naturally Fractured Reservoirs (NFR) constitute a challenge for the oil industry due to its importance in hydrocarbon production and the technical complexity they represent, because well's productivity in carbonated formations is influenced by fracture systems that govern the fluids motion within reservoirs. This approach is oriented to the analysis of a very complex NFR, where we show the results obtained through a dynamic characterization methodology focused on new opportunities in a High Pressure-High Temperature (HP-HT) coastal mature oilfield with high water cut production. The proposed methodology is based on a full analysis starting from the pressure-production historical data, fluids properties, dualporosity material balance, a detailed static model update (petrophysics, core analysis, petrography, fracture analysis, sedimentology-diagenesis and structural geology), flow units discretization, Water-Oil Contact (WOC) advance monitoring in each block, Pressure Transient Analysis (PTA) (determination of preferential flow direction and interference), and Rate Transient Analysis (RTA). This methodology allowed to determine the real Original Oil in Place (OOIP) and the proper recovery factor according to the type of NFR and its characteristics, to detect different WOC's for each block that were hydraulically connected to each other but with a different dynamic behavior among them, the detection of heterogeneities, facies changes and faults that originally were not mapped, sweet spots location, better distribution of the petrophysical properties, fracture analysis, static model reinterpretation based on the dynamic behavior, reservoir connectivity analysis (among blocks) and the generation of improved production forecasts based on an exploitation strategy especially designed for the current conditions and needs of the field; all of this contributed to have a better understanding of the reservoir and a good numerical simulation model.
Lin, Tengfei (Department of Middle East E&P, RIPED, PetroChina) | Wang, Nai (Department of Middle East E&P, RIPED, PetroChina) | Wang, Weijun (Department of Middle East E&P, RIPED, PetroChina) | Li, Nan (Department of Middle East E&P, RIPED, PetroChina) | Yang, Shuang (Department of Middle East E&P, RIPED, PetroChina) | Liu, Yumei (Department of Middle East E&P, RIPED, PetroChina) | Dong, Junchang (Department of Middle East E&P, RIPED, PetroChina) | Zhang, Qingchun (Department of Middle East E&P, RIPED, PetroChina) | Guo, Rui (Department of Middle East E&P, RIPED, PetroChina)
Bioclastic limestone reservoir is playing a dominant role in the petroleum industry of Middle East. The oilfield in this paper belongs to long-axis asymmetric anticline. The S formation of Cretaceous period universally developed bioclastic limestone of carbonate platform system. It is the reservoir heterogeneity that severely limits the oilfield development.
We firstly analyze the lithofacies based on the core and thin section. Then the detailed well and seismic interpretation illustrate the sequence stratigraphy and facies analysis, and tectonic evolution are analyzed to restore sedimentary procedure from Palaeocene to late Pliocene stage. Ultimately, high quality reservoir of bioclastic limestone are depicted according to comprehensive analysis.
This paper offers reference and inspiration for bioclastic limestone reservoir: reef-beach complex and sweet spots in tidal-channel are dominant reservoirs for bioclastic limestone of Middle East.
The Kenshen tight gas field, located on the northern margin of the Tarim basin, western China, has extreme reservoir conditions of an ultra_depth reservoir (6500 to 8000 m) with low porosity (2 to7%), low matrix permeability (0.001 to 0.5 md), high temperature (170 to 190°C), and high pore pressure (110-120 MPa). Those conditions result in high completion costs and a significant difference in individual well production rates; with only one-third of wells drilled meets expectations. Previous studies focused on natural fracture(NF) and attempted to classify reservoir qualities based on the density of NF. Unfortunately, some NFs were closed or cemented by clay or calcite, and it is hard to distinguish open NF from closed NFs using well images in oil-based mud, which is widely used in this tight gas field for reservoir protection. Thereby, no positive correlation between NFs density and productions has been identified, even with the same stimulation treatment.
In this study, a comprehensive geological study was conducted to find a new way of characterizing the effectiveness of NF. First, the initial and development stages of NFs were recontructed through a tectonic activity study. Two stages were detected and showed different strikes. Second, petroleum system modeling technology was applied to simulate source rock maturation and gas migration, which revealed that gas generated in the Jurassic source rock migrated to the Cretaceous reservoir formation through faults activated in the same period as the late stage of NFs development. NFs developed earlier were closed or cemented by calcite of later deposition; those at late stage were open and effective for gas charge. Also in this study, Advanced analyses of borehole images indicated an alternative way to delineate NFs developed at different stages using geometry (i.e, crossed NFs shall include those ones developed at later stage). Parallel NFs with its development unidentified can be classified through the intersection angle of fracture strike and maximum stress direction. The smaller the intersection angle is, the easier it is for stimulation and alos the higher for the well production. Based on this study, we have divided reservoirs in the study area into three classes: class 1, reservoir with crossed NFs; class 2, reservoir with fractures of small intersection angle; class 3, reservoir with fractures of large intersection angle. This innovative reservoir classification through NF geometry is currently used in the field to determine formation stimulation method. Class 1 reservoir can benefit from acidizing alone with low completion cost. Class 2 reservoir of should be hydraulically fractured with acid. Class 3 reservoir of should be fractured with sand and proppant sand to achieve economical production.
Reservoir classification with NFs geometry had been applied successfully to guide stimulation design in the Keshen tight gas reservoirs. It is a practical and feasible way to choose the most appropriate stimulation treatment method to optimize well performance and avoid restimulation to reduce costs for this extreme type of tight gas field in western China.
Reservoirs and the lateral seal of stratigraphic traps are controlled by the depositional environment or diagenesis. The recognition of facies and lithology from seismic attributes is an effective approach for identifying stratigraphic traps related to the depositional environment. In this paper, the occurrence of stratigraphic traps related to depositional environment in Permian aeolian clastics and Jurassic carbonate-evaporites was studied. To identify these stratigraphic traps, multiple seismic attributes were classified using supervised and unsupervised artificial neural networks (ANNs), which allowed the recognition of seismic facies and lithology.
Neural networks are a powerful classification technique, which incorporates multiple attributes into a number of classes to identify sedimentary facies. Two algorithms comprising supervised and unsupervised neural networks are commonly implemented. With a supervised learning algorithm, prior information such as typical facies at the control wells are required to train the multilayer perceptron (MLP) network. With an unsupervised algorithm, only seismic data is input to the neural network, and competitive-learning techniques are employed to classify or self-organize the data based on its internal characteristics. Without prior information, the output classes are not labeled with lithofacies. According to the availability of prior information, supervised and unsupervised learning were applied to recognize dune-playa and carbonate-evaporite combinations, respectively. To characterize the depositional environments, joint interpretation with a geological model is necessary for both supervised and unsupervised classification.
Two major findings have been derived from this work. First, the learning technology based on ANNs is effective to recognize sedimentary facies. The microfacies and lithologies identified by both supervised and unsupervised ANNs are very consistent with the drilled wells. Second, the recognition of depositional facies and lithology can characterize the stratigraphic traps in the study areas. Lateral seal plays a key role in stratigraphic traps. Playa siltstone and tight lagoonal limestone constitute the lateral seal in dune-playa and carbonate-evaporite combinations, respectively.
The Montney Formation is a major shale gas and shale oil producing stratigraphical unit of Lower Triassic age in the Western Canadian Sedimentary Basin in British Columbia and Alberta. The potential resource is estimated at 449 trillion cubic feet of marketable natural gas, 14,521 million barrels of marketable natural gas liquids (NGLs) and 1,125 million barrels of oil. The hydrocarbon resource is unlocked using horizontal drilling followed by various fracture stimulation techniques from 25 to 75+ stages. As stage counts increase and lateral lengths are extended further to stimulate more formation, the challenges of efficiently completing a producing well is a continuous cycle of technique development and equipment improvements.
Hydraulic isolation between fracture stimulation stages is established using mechanical methods deployed as an integral part of the production casing string or inserted into the production casing string during the fracture stimulation. In the Montney, the method of
Adams, Adeniyi A. (Baker Hughes, a GE Company) | Soliman, Ahmed M. (Baker Hughes, a GE Company) | Deng, Lichuan (Baker Hughes, a GE Company) | Jurdi, Imad (Baker Hughes, a GE Company) | Al Hosani, Mohamed Salem (ADNOC Onshore) | Al Menhali, Adnan (ADNOC Onshore) | Ardila, Jose David (ADNOC Onshore)
The challenge was to achieve more reservoir contact in a cretaceous tight reservoir to improve production and maximize recovery. Multilateral well campaigns were performed to meet these objectives.
This case study describes an effective workflow for performing openhole sidetracks in this challenging medium-hard carbonate formation. The workflow maintained reservoir contact and achieved the desired production objectives.
Two 6-in. multilateral drain sections were successfully drilled by performing openhole sidetrack using the continuous proportional steering method (CPSM). This method is not new to the industry, but this case study describes the systematic, unique workflow that was designed and followed to ensure a successful sidetrack in this low-porosity, hard formation.
The sidetrack implementation started by creating humps at inclinations ranging from 88 to 91 degrees into the formation in the original 6-in. section. These humps were confirmed using near-bit inclination data (4.5 ft from the bit) and were identified as the sites for initiating a sidetrack. This paper discusses the best practices that were key to the successful execution of the project in one run on the first attempt.
After the sidetrack, use of appropriate combinations of shallow and deep logging-while-drilling (LWD) measurements in the same bottom hole assembly (BHA) enabled the direct geosteering of the well, exposing more reservoir surface area than planned.
A reduction of 10% from the planned well duration was achieved. Two 6-in. laterals, each approximately 4000 ft, were drilled in a single run and 100% reservoir contact was achieved.
This experience proved that planning and precise execution could enable drilling of openhole sidetracks, even through hard formations. These sidetracks can then achieve fishbone wells with desired reservoir contact and realize the field development objectives in a technically robust and cost-efficient manner.
CPSM does not rely on a pressure drop for steering. Although this proof of concept was performed in a relatively hard formation, similar workflows with appropriate drilling engineering may be applied to less-competent formations as well. The detailed procedure and flowchart created from the experience with the sample well can be adopted for use in similar applications.
Al-Ibrahim, Abdullah (Kuwait oil Company) | Al-Bader, Haifa (Kuwait oil Company) | Duggirala, Vidya Sagar (Kuwait oil Company) | Ayyavoo, Mani Maran (Kuwait oil Company) | Subban, Packirisamy (Kuwait oil Company) | Almulla, Sulaiman (Kuwait oil Company)
The objective is to achieve improved productivity from an unconventional fractured reservoir using uncemented liner completion over the standard cemented liner completion.
Exploration and production of an unconventional fractured Najmah & Sargelu (NJSR) reservoir in Jurassic section has been a challenging task due to the presence of challenging reservoir quality like tight fractured limestone, very low matrix porosity, uncertainty on natural fractures, high stress, etc. NJSR reservoirs are considered as a secondary target. As the deeper primary reservoir needs to be evaluated, testing of NJSR reservoir takes considerable time after drilling which lead to permanent plugging of NJSR fracture network by invaded oil based mud (OBM). Mixed success has been observed on sustainable production from NJSR exploration wells. Production from fractured reservoir relies primarily on intersecting interconnected natural fractures, optimal drilling and special completion technique. Protecting the natural fractures present in NJSR reservoir can increase the reservoir contact and production.
A study conducted on this reservoir suggested to target only NJSR formation and install uncemented liner to eliminate the damage caused by cement invasion and achieve sustainable production. The study also emphasized to activate the well as soon as possible after completion to revive fracture conductivity. Uncemented perforated liner completion method has been selected for field trail in an exploratory well to maintain borehole integrity and control production of solids, connecting open fractures, increase inflow area and enhance production.
The case study well targeting NJSR reservoir was drilled upto 14,925ft and 5" uncemented CRA liner was installed against reservoir section. The well was completed with permanent packer using 3-1/2" production tubing. Well fluid was displaced with diesel, mud clean solvent was spotted inside 5" production liner and the uncemented liner section was perforated using wire line guns in underbalanced condition. The well became active after perforation and flowed naturally oil and gas with 1.8% H2S.
A successful implementation of uncemented liner completion technique in an exploratory well for the first time proved to be effective in fractured reservoir compared to the conventional cemented liner completion. Application of uncemented liner completion technique has preserved fracture connectivity, eliminated formation damage due to cement invasion and reduced time and cost of cementing and stimulation. During initial testing the first field trial well has produced oil and gas without stimulation, which is a success compared to conventional method.
As a final recommendation from the study, future exploratory wells targeting NJSR reservoir will be drilled in high angle trajectory and completed using uncemented slotted liner with swell packers to improve the productivity.
This paper will discuss in details on new completion strategy, testing of deep HPHT well and performance of first exploratory well completed with uncemented liner.