A. H. Khan, M. Faisal (Pakistan Petroleum Limited) | Abid, M. Faraz (Pakistan Petroleum Limited) | Fareed, Abdul (Pakistan Petroleum Limited) | Javed, Zeeshan (Pakistan Petroleum Limited) | Khan, M Noman (Pakistan Petroleum Limited) | Hashmi, Shariq (Pakistan Petroleum Limited)
Technical evaluation and subsequently devising an appraisal and development strategy of a structural cum stratigraphic reservoir based on a discovery well only is always challenging. The reservoir under discussion was discovered as a structurally bounded trap and the appraisal wells were drilled on NW-SE direction along with the main bounding fault based on this understanding. However, presence of hydrocarbon below the spill point, anomalous sand thickness, lateral facies and reservoir quality variations observed in few of the wells indicated stratigraphic component in the field. Further complexity was added when the deepest tested gas was assigned on the structural map which showed extension of the hydrocarbon play outside the block boundary where the area was under different operating company that later drilled multiple wells near the block boundary. Therefore, it was critical to estimate correct initial gas in-place and percentage distribution of hydrocarbon across the lease boundaries.
Well location map for the studied field
Well location map for the studied field
The objective of this paper is to present workflow that integrates multiple dataset to understand the field's hydrocarbon filling mechanism. Detailed geophysical and Petrophysical work has been carried out, which includes building of sequence stratigraphic framework, preparation of seismic attribute maps, understanding of the depositional setting for all the individual sand units encountered in all the wells, rock quality assessment (core and log methods with integration of capillary pressure curves), free water level (FWL) assessment, permeability modelling using machine learning approach (NN), pore throat radius estimation to relate hydrocarbon filling mechanism and saturation-height function modelling to build consistent 1D water saturation model.
Comprehensive dataset has been acquired to evaluate the potential of the field that covers 3D seismic for the entire field, biostratigraphic analysis for seven (7) well, conventional logs in twelve (12) wells and advance measurements like Elemental Capture Spectroscopy and high-resolution resistivity images in five (5) wells. Core analysis data also acquired in five (5) different wells including routine core analysis, capillary pressure measurements using high pressure mercury injections, pore throat radius, relative permeability measurements (Centrifuge), formation resistivity factor measurements and sedimentological analysis (XRD & thin section) to overcome the challenges and defining the uncertainty associated with initial gas in-place.
Sequence based boundaries were defined to correlate individual sand bodies using the core data, image logs, elastic logs, seismic transacts and attribute maps for understanding the depositional setting. Lat-er these correlations were used to build a consistent petrophysical model including VCL estimation from Gamma/Neutron-Density/Sonic Density methods which was validated with ECS/XRD data. Porosity model was developed and validated from the core porosity followed by variable "m" estimation from the porosity/m relationship using the SCAL data. Later on, the consistent water saturation (Sw) models were built for all the studied wells. Permeability models were built using Neural Network (NN) where core-based permeability used for calibration and the model was tested qualitatively with the mobility and the well test permeability. For the validation of Sw from the logs, capillary pressure-based flow units were built using FZI/RQI, Winland & BVW (log) methods to define flow units defined through the core data. It was observed that the Winland R35 method-based pore throat radius had good correlation with the Sw log. FWL from MDT to estimate the height of the gas column, Skelt Harrison equation to capture the shape of the capillary pressure curve and Swi from the Centrifuge analysis were used to calibrate MICP end point which helped in building consistent Saturation-height functions. Results showed good to excellent match from the modeled Sw (Pc) vs Sw(log).
Khan, Muhammad Hanif (Independent) | Maqsood, Tahir (Tullow Pakistan) | Jaswal, Tariq Majeed (Pakistan Oilfield Ltd) | Mujahid, Muhammad (Spec energy DMCC) | Malik, M. Suleman (Qatar Petroleum) | Jadoon, Ehtisham Faisal (UEP Pakistan) | Hakeem, Uray Lukman (Qatar Petroleum)
This article investigates the seismic reflection geometries (possible reservoir) of Paleogene of Offshore Indus Basin Pakistan (shelf area) from 2D seismic and make an analogue with the proven carbonate reservoir geometries found in countries such as Canada and Middle East. The 2D seismic data are used to interpret the possible carbonate features and methods to identify them and define its depositional setting on the carbonate platform. The offshore Indus Basin is tectonically a rift and a passive continental margin basin, located in Offshore Pakistan and Northwest India where carbonates were deposited on the shelf and the deep offshore area during early post-rift phase. In the deep offshore area, carbonates were set on volcanic seamounts during the Paleogene age. In Paleogene, the Indian Plate was passing through the equator in the conditions of warmer water with appropriate water salinity, where those conditions were suitable for the growth of organisms responsible to develop reefs in the Offshore Indus area. The available seismic data analysis has indicated the possible presence of different carbonate reefs on the shelf. The seismic data enabled to define the possible carbonate Rimmed shelf depositional model in the area. The aim of this article is to highlight and analogue carbonate seismic geometries, their internal architecture in the Paleogene interval of the Offshore Indus Basin (shelf area) and how to identify them, which may help for further exploration in Offshore Indus Basin.
Is Surfactant Environmentally Safe for Offshore Use and Discharge? The current presentation date and time shown is a TENTATIVE schedule. The final/confirm presentation schedule will be notified/available in February 2019. Designing Cement Jobs for Success - Get It Right the First Time! Connected Reservoir Regions Map Created From Time-Lapse Pressure Data Shows Similarity to Other Reservoir Quality Maps in a Heterogeneous Carbonate Reservoir. X. Du, Y. Jin, X. Wu, U. of Houston; Y. Liu, X. Wu, O. Awan, J. Roth, K.C. See, N. Tognini, Shell Intl.
By International Petroleum Technology Conference (IPTC) Monday, 25 March 0900-1600 hours Instructors: Olivier Dubrule and Lukas Mosser, Imperial College London Deep Learning (DL) is already bringing game-changing applications to the petroleum industry, and this is certainly the beginning of an enduring trend. Many petroleum engineers and geoscientists are interested to know more about DL but are not sure where to start. This one-day course aims to provide this introduction. The first half of the course presents the formalism of Logistic Regression, Neural Networks and Convolutional Neural Networks and some of their applications. Much of the standard terminology used in DL applications is also presented. In the afternoon, the online environment associated with DL is discussed, from Python libraries to software repositories, including useful websites and big datasets. The last part of the course is spent discussing the most promising subsurface applications of DL.
The concept of unitization albeit has been in its infancy under the existing upstream exploration & production oil & gas legal regime in Pakistan, even though there are many straddling reservoirs which continue to be in communication. Therefore, the need to develop a comprehensive legal & regulatory framework that covers all aspects of unitization of straddling reservoirs and closing all pending unitization issues is the dire need of the hour. This is not only critical from the Governments' perspective but is important for the companies subject to unitization to effectively monetize their returns on investment.
The paper concludes that in the presence of a strong regulatory framework comprehensively addressing unitization of straddling reservoirs, upstream companies would be forced to unitize, either by incentives or by compulsion while the regulator shall continue to supervise their work programs regarding field development. The paper attempts to provide creative guidance for setting up a comprehensive legal/regulatory framework addressing unitization.
Unitization is the process of joint development of a hydrocarbon reservoir which extends across block boundaries of two or more production licenses (leases in Pakistan) operated by different lease groups (unincorporated joint ventures in Pakistan). Under unitization, each lease group agrees that the straddled field is aggregated as a “unit”, in which each lease group is entitled a percentage interest called “Tract Participation”. Tract participation defines the share of hydrocarbon volumes and cost of each lease group in the common pool. The percentage interest of each leaseholder (company) in the “Unit” is called its “Unit Interest”, which is based on working interest of leaseholder in the lease group and its tract participation.
The objectives of unitization include but are not limited to preventing waste (economic, underground, surface & environmental) by assuring efficient, orderly, and environmentally responsible development and by facilitating joint operations to maximize efficient hydrocarbon recovery. It also provides a means to fairly allocate hydrocarbon reserves and costs among lease groups and resolving disputes that may arise. The concept of unitization is elaborated in Fig-1.
A workflow is presented in this study named Fracture Evaluation & Design System (FEDS) that couples established technique of nodal analysis (well performance evaluation) and Quasi-3D (type of Pseudo-3D) hydraulic frac models. This methodology of hydraulic frac simulation is more robust in predicting post-frac production rates from fractured wells specifically in unconventional reservoirs like shales and has several advantages over utilizing frac models in isolation. The results from FEDS are compared with commercial frac simulators and discrepancies are noted. This workflow is divided in two segments, flow in frac (or reservoir) and flow in wellbore. The frac element is calculated through Quasi-3D frac model, a published hydraulic frac model that calculates frac geometry (frac length, width & height) in asymmetric multilayer formations such as Pakistan’s Shales. This calculation is used to estimate the dimensionless fracture conductivity (FcD) which is a measure of effectiveness of the frac. These calculations are combined with reservoir parameters such as pressure, permeability and skin to generate deliverability profile or Inflow Performance Relationship (IPR). This IPR generated from calculated fracture geometry & conductivity inherently accounts for uncertainty of formation stresses, frac height implications, effect of permeability variation etc. This is a numerically calculated IPR, while fracture growth is being modelled; IPR is constantly updated based on fracture model results in a fully coupled setting. Second element of wellbore hydraulics or Vertical Lift Performance (VLP) is calculated using several published correlations such as Gray et al. The idea behind incorporating VLP in frac simulation is to model effects of water holdup, slippage, multiphase flow etc. Most commercial frac simulators utilize correlations of FcD to estimate post frac production, such as cinco-ley et al correlation. However, often production at surface is hampered due to wellbore effects such as water slippage. This is one of the major reason, despite having reliable input data, design post frac profile is much higher than realized production. The working of this workflow is validated by applying on two field fracture treatments. One of this treatment is in conventional sandstone reservoir while other is unconventional. The design & post frac production prediction is conducted in published frac models (that are used by commercial simulators) and using Quasi-3D frac model in FEDS. In all cases, production predicted by FEDS is significantly lower than commercial simulators. Main frac treatment is conducted as per design in these two reservoirs and actual post frac production is measured. The instantaneous gas production from both reservoirs is in better agreement with production predicted by FEDS validating the calculations of this workflow.
The objective of this study is to find out a novel way of overcoming uncertainties associated with successfully locating best sites for drilling infill development wells. These uncertainties are usually associated with the non-uniqueness of responses from such petrophysical properties as porosity, permeability, and water saturation created through the static reservoir modeling process, leading, in many cases, to misleading allocation of proposed infill well locations.
In order to achieve this objective, a normalized combined super-property, composed of selected petrophysical properties, was created. This new property was calibrated using certain scalar factors that were given to each property in order to bring the real distribution and weightage of each of the component properties into effect.
The main observation from the present study is that the novel combined super-property has proven to give more realistic and accurate allocation of proposed infill well sites. This observation was documented through practical validation of negative (wet) wells, giving misleading positive responses from conventional petrophysical properties, while giving correct accurate negative response, and vice versa, using the novel combined super-property. Incorporating this novel technique into the high-resolution stratigraphic model resulted in maximizing property distribution accuracy per reservoir layer. More accurate prediction of lateral and vertical distribution of reservoir facies and petrophysical properties in three dimensions was then achieved and resulted in outlining a number of new well locations based on this technique.
The value of this novel technique lies in significantly reducing the risk of drilling negative boreholes based on static reservoir models. This is because each individual value of a property, such as water saturation, can be the result of a multitude of factors, including natural factors and/or data acquisition, processing, & interpretation pitfalls, therefore, not necessarily indicating presence of hydrocarbons. The present study reduces non-uniqueness of each individual property response using the scaled combined super-property.
The first survey campaign with a focus on the presence of noble gases (Helium) and Carbon Dioxide was carried out, with a spot sampling, on wells drilled in a thin-layered, siliciclastic reservoir. A real-time continuous monitoring system was developed and deployed to acquire data while drilling, with the aim of: evaluating the presence of Helium-rich layers (economically producible) and understanding the link between Helium and gas- bearing levels (Helium used as a tracer).
Comparative tests were made on several instruments through the analysis of gas samples with a known Helium content. The analyzer, Pollution MicroGC, met the client’s requirement because it was able to detect He concentrations below 50ppm.
This new gas chain system, made up of the MicroGC analyzer together with the degassing system, was run and fine-tuned in various geological environments (in siliciclastic (thin-layer reservoirs) and carbonates (fractured reservoirs)). A sampling methodology was developed that encompasse both the hardware requirements and sampling. Helium is a highly volatile element, and proper sampling lines and sampling materials were selected and tested. Procedures for efficiency checks were put in place as well as procedures for gas sampling in the event of gas shows. Samples were collected mainly for isotopic analysis and evaluation of the origin (Crust/Mantle) of the potentially associated CO2.
While working in fractured carbonates reservoirs, the system showed further potential with respect to real-time CO2 monitoring, even at low concentrations (<100ppm, quite below normal operative range of standard sensors), and lag time determination with heavy losses. Reliable Carbon Dioxide monitoring while drilling can dramatically improve early detection of potential operative risks (changes in mud rheology, poor hole cleaning and drill pipe corrosion), thus avoiding the onset of immediate operative issues (cost savings and NPT). Furthermore, even with heavy losses, the new MicroGC detection system, via the Helium used as a calibration gas, enables for safe (inert gas) and efficient (good tracer element) lag time measurements.
A novel approach to the detection of mud-entrained gases while drilling has enable to enrich significantly the quality and quantity of reservoir information available in Real-Time. This approach has involved the development of new detection instruments and the adaptation of existing technology to a new scope, and it was made possible by a constructive workflow involving two separate companies (an oil company and a service provider) and distinct departments within such companies. Such workflow enabled to plan, support and correct the project while drilling in order to maximize the value of the data collected. A gas analyzer able to measure dozens of distinct light hydrocarbon components simultaneously was deployed along with a detector dedicated to the quantification of non-hydrocarbon gas species, focused on the measurement of CO2, He and H2, even in very low concentrations. An interpretation model was applied to such data to infer from it reservoir characteristics. The main result obtained was, in terms of hydrocarbons, an increased depth of investigation of light hydrocarbons composition in Real-Time, obtaining for the first time data normally extracted from production fluid samples at a much later stage. Furthermore, observing the heavy gases behaviour we reached a better understanding of the mechanism of liberation of gas from mud and the effect of contaminant fluids. These observations enable to better assess the value of gas data and to more accurately quantify data uncertainty.
In terms of non-hydrocarbons, high-resolution gas detection was used to identify the presence of Helium and to evaluate the possibility to use it as a tracer to correlate known levels and types of mineralization. The whole system has allowed to identify the passage between the main reservoir formations, secondary lithological contacts (carbonates / clays) and different mineralizations. The noble gas, due to its physical properties, is theoretically differently distributed depending on its solubility in the fluid it is in contact with: in an ideal situation is so possible to identify the types of mineralization on the basis of different quantity of Helium detected in Gas, Water and Oil bearing intervals respectively. The analysis also monitored the levels of CO2 and, where this gas was in significant quantities, we proceeded to the sampling and characterization to determine the type / source of this gas in order to estimate how much of this gas can be present in the well, and consequently, evaluate the productivity of the well and choosing the facilities to be used.