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.
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.
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.
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.
Yassin, Mohamed A. (Geosciences Department, CPG, KFUPM, Dhahran Saudi Arabia) | Abdullatif, Osman M. (Geosciences Department, CPG, KFUPM, Dhahran Saudi Arabia) | Makkawi, Mohammad H. (Geosciences Department, CPG, KFUPM, Dhahran Saudi Arabia) | Yousif, Ibrahim M. (Geosciences Department, CPG, KFUPM, Dhahran Saudi Arabia) | Osman, Mutasim S. (Geosciences Department, CPG, KFUPM, Dhahran Saudi Arabia)
Well exposed Jurassic outcrops belt in central Saudi Arabia provides good outcrop analogs which can be utilized to capture the high resolution facies types and architecture that might help to fill the inter-wells gap in the subsurface. This study is focused on the characterization and modeling the facies types, body geometries deposited in geomorphic elements of carbonate ramp system and the distribution of the reservoir properties on it. Three-dimensional models for the different facies-body geometries were conducted to provide accurate stochastic representation. This study was conducted at a selected Jurassic outcrop reservoir analog that exposed around Riyadh area. The Mesozoic carbonate strata of central Saudi Arabia are interpreted to have been deposited in ramp systems and exposed in hundreds of kilometers in the strike and dip direction of palaeoshoreline. The study integrates detailed sedimentological and stratigraphic analysis from outcrop strata to capture facies-body geometries and their petrophysical properties on the ramp system. Nine lithofacies were interpreted from the stratigraphic sections. Spatially, the porosity and permeability show different ranges of heterogeneity from micro to meso and macro scales. Laterally, the reservoir properties show steady variations in contrast with the abrupt change vertically. This variation seems to be related to the sedimentary structure, grain size, and degree of cementation. Different pore types were recognized in the studied intervals, which include fracture, intraparticle, moldic and intercrystalline porosities. Several 3D facies models were constructed using sedimentological and stratigraphic data that collected from the field. These models express the complex and heterogeneous relationship between facies-body geometries in the outcrop precisely. Integration of these data to subsurface equivalent reservoirs will provide qualitative and quantitative information useful for understanding and predicting reservoir quality and architecture in carbonate ramps.
Al-Obaidli, Asmaa (KOC) | Al-Nasheet, Anwar (KOC) | Snasiri, Fatemah (KOC) | Al-Shammari, Obaid (KOC) | Al-Shammari, Asrar (KOC) | Sinha, Satyendra (KOC) | Amjad, Yaser Muhammad (Schlumberger) | Gonzalez, Doris (BP) | Gonzalez, Fabio (BP)
The Magwa-Marrat field started production early 1984 with an initial reservoir pressure of 9,600 psia Thirtysix (36) producer wells have been drilled until now. By 1999, when the field had accumulated 92 MMSTB of produced oil and the reservoir pressure had declined to 8000 psia, the field was shut-in until late 2003 due to concerns on asphaltene deposition in the reservoir that could cause irreversible damage and total recovery losses. The field was restarted in 2003 an it has been in production since then. By April 2018 the field had produced 220 MMSTBO, with the average reservoir pressure declined to 6,400 psia. As crude oil has been produced and the energy of the reservoir has depleted, the equilibrium of its fluid components has been disturbed and asphaltenes have precipitated out of the liquid phase and deposited in the production tubing. There is a concern that the reservoir will encounter asphaltene problems as the reservoir pressure drops further. The objective of this manuscript is to present the process to understand the reservoir fluids behavior as it relates to asphaltenes issues and develop a work frame to recognize and mitigate the risk of plugging the reservoir rock due to asphaltenes deposition with the end purpose of maximizing recovery while producing at the maximum field potential Data acquired during more than 30 years have been integrated and analyzed including 22 AOP measurements using gravimetric and solid detection system techniques, 17 PVT lab reports, 1 core-flooding study and 1 permeability/wettability study. Despite the wide range of AOP measured in different labs, it was possible to determine that the AOP for the Magwa-Marrat fluid is 5,600 500 psia and the saturation pressure is 3,200 200 psia. Results of this fluids review study indicates that it might be possible to deplete the reservoir pressure below the AOP while producing at high rates.
Techniques for 3D seismic interpretation by geoscientists are continuously undergoing improvements, and future exploration is anticipated to continue to benefit from high-confidence first pass interpretations utilizing all of the available seismic and well data. Workflows have been developed on a'super-merge' 3D volume to produce attribute-enhanced chronostratigraphic stratal surfaces, allowing interpretation of regional-scale seismic facies and associated seismic geomorphology and tectonostratigraphy. In this example, a semi-supervised machine-based learning workflow has provided rapid turnaround interpretation of the structural framework and chronostratigraphy throughout the entire 3D seismic volume, maximizing the value of the seismic information. This workflow consists of a three-step auto-tracking workflow to build a Relative Geological Time (RGT) geo-model directly from the seismic volume. This enables more time to spend on geological validation and interpretation of the stratal surface seismic geomorphology. Study results have provided the foundation for rapid turnaround well and seismic integrated play fairway maps; a powerful tool for stimulating exploration in mature areas or wildcat acreage assessment. This study focused on Middle and Upper Jurassic carbonates deposited on a broad low angle platform on the Arabian Plate. Interpreting in map view on RGT constrained stratal surfaces with attributes such as, relative acoustic impedance and spectral decomposition, is invaluable for visualization since the stratal surface follows the morphology of the imaged geologic features. The ability to select any stratal surface within the volume and flatten, either on a seismic display or the Relative Geological Time geo-model, is particularly useful to establish the timing of major tectonic episodes and accommodation space fluctuations.
Africa (Sub-Sahara) Sonangol's deepwater Orca-1 well encountered oil in the presalt layer of Block 20/11 in the Cuanza basin offshore Angola. The well reached a measured depth of 12,703 ft. Initial well tests saw flow rates of 16.3 MMcm/D of gas and 3,700 BOPD. Cobalt International Energy (40%) is the operator, with partners Sonangol Research and Production (30%) and BP Exploration Angola (30%). Asia Pacific Premier Oil's Kuda Laut-1 well in Indonesia's Tuna production sharing contract has encountered 183 net ft of oil-bearing reservoir and 327 net ft of gas-bearing reservoir. Following evaluation operations, the well will be sidetracked to drill the Singa Laut prospect in an adjacent fault block. Premier is the operator (65%), with partner Mitsui Oil Exploration Company (35%).