Intelligent Choke Management tool
Development of the automated system to guide best choke management strategy in real time for flow back of wells during well test or ramp up operation with a goal of reduction of clean-up time while maintaining the productivity of wells. (Probably also include the purpose of slug-control and start-up procedure for different completion (especially the frac-pack completion) for the purpose of sand production management.
Presently most of the industry uses pre-determined industry standard choke management in well testing or production ramp up operations. While in order to reduce clean-up time it is desirable to open choke to maximum size, it may lead to excessive drawdown and other problems like sand production. Hence, it is vital to come up with optimal choke management strategy which should always be based on intelligent inputs from real time pressure data & past experiences. We propose the tool for determining the optimal choke size to reduce clean-up time and enhance production based on data analysis of historical reservoir & production records and real time tubing pressure data stream.
Development of automated intelligent system for choke management using engineering analysis (nodal analysis) & comprehensive historical database of flow back in analogous reservoir, which would recommend engineers about optimum choke size in real time. This system can guide user about reservoir behavior at various drawdowns for sand/fines migration, what choke size will result in stable flow (constant rate & GOR etc.), possibility of hydrate formation in drill string or on surface based on real time pressure-temperature data stream. The system would be capable of automatically capturing critical information from DDR (Daily drilling report) & DGR (Daily Geological report) using text mining and use it to best predict choke management strategy.
Advantages of using proposed methodology
Reduction in clean-up time by use of informed decision along with maintaining quality of acquired pressure data (stable GOR & flow rate).
Better parameters to quantify clean-up of well rather than just relying on visual BS&W%.
How it is different from already existing tools
- Presently all tools use nodal analysis to predict choke-rate behavior for the wells but no tool is present which uses real-time THP as a input to direct future choke size for efficient reservoir management
- All present tools require engineers to manually input geological & drilling parameters which are often cumbersome to obtain from piles of drilling and geological reports. The automated system can read pdf versions of report and use parameters from them directly as an input for prediction of optimal choke size.
- At present no tool gives prediction of clean-up time and how can it be optimize. This tool can have additional capability of predicting hydrate formation.
Visualization of Real-time surveillance & quality control of wireline formation test Data
Wireline formation tests (WFT) have become widely acceptable and commonly used method to provide virgin reservoir pressure data and collect quality downhole PVT samples. Wireline formation testers uses a probe that can be positioned at a selected depth in the formation to provide accurate measurement of pressure at any point and fluid type. In order to collect these important pressure data points with depth several pretests (drawdown) have to be given from probe at depth for which pressure is required. Fig- 1 gives the typical probe response of pressure near the well.
- Figure 1 : Typical Probe pressure response
The last stabilized buildup pressure is interpreted as formation pressure. Due to high resolution of gauges these days it becomes critical to wait for stabilization of buildup pressure. Error while collection of this data can lead to gas gradient being interpreted as gas condensate or vice versa. The complications of low formation mobility and drilling fluid invasion also makes it difficult to obtain accurate reading of pressure data and often we have to do several cycles of pretest to collect accurate data before tool is moved to next depth. Accuracy and time required for pressure stabilization is also dependent on drawdown rate and volume. Presently operators have to use common spreadsheet applications for real-time interpretation of data and the quality of data is based on engineer doing the job. Also spreadsheet programs are often not linked with real time data cloud and engineer have to manually enter data in spreadsheet. Schlumberger provides its own proprietary software called In-situ pro™ but that is often not available to disposal of operating companies.
We propose preparation of a real time tool to aid pressure interpretation of WFT’s which can guide operators about information on time & drawdown required for correct pressure stabilization & repeatability. Significant rig time can be saved if engineer’s interpretation can be aided with automated suggestion of drawdown volume and rate (in 2014 mark proett from Aramco had a paper on this methodology).
Presently no software includes effect of changed stress level due to drilling of well and mud circulation based on Mandel-cryer effect/kirsch’s solution. Based on time elapsed since drilling of hole to running of wireline the change in formation stresses near wellbore could be predicted and included in tool to correct pressure data to these localized effects.
Database of reservoir and geomechanical properties from core analysis results
While core analysis provides the most direct information about reservoir. Huge amount of data is still unused in commercial reservoir simulator. This unused data could lead to critical information for example: direct measurement of core compressibility is possible by analysis of diameter of retrieved core, as often we get cores of reduced diameter (as observed in MJ-field). This phenomenon could be analyzed to get direct information of in-situ formation compressibility, if all the coring/drilling parameters are known.
We propose a preparation of comprehensive database of reservoir and geomechanical properties from core analysis results for all the fields operated by RIL. Use of this in-house database could be highly beneficial for operating engineers and geologists to gain critical insights in case of limited information availability. The database will include state of art data mining and visualization techniques helping management to gain insight into previously ignored information.
Reservoir characterization using coupling of tidal signals with downhole pressure transient analysis
Interpretation of ocean (and barometric) tide effects is based upon a cyclic change to the head of water (or air) which alters the overburden and thus reservoir pore pressure. Accurate measurements of surface ocean tide are simple to make and can be compared to in phase to measurements of the reservoir pressure. Thus, using this technology we can measure compressibility and porosity along with variation of compressibility away from the wellbore through interpretation of shift of phase between surface and bottom hole pressure measurements.
Fluctuations of pressure and liquid levels in wells that are connected with sufficiently confined subsurface fluids provides a means of obtaining quantitative data on the earth strains. These pressure fluctuations in a static reservoir can be due to earth or ocean tides. For an offshore reservoir with unconsolidated sands the tidal signal transmission efficiency is relatively large and hence it become possible to extract tidal signals from downhole gauge. While downhole pressure gauge radius of investigation is dependent on time of flow period. Ocean tides, owning to their vast extend as compare to the reservoir affects a much larger area. Thus, in theory for a static reservoir it becomes possible to detect reservoir compartments by analysis of induced pore pressure changes due to ocean tides. Detection of this phenomenon in the well could also represent a new piece of information about the fluids present in the vicinity of the well. Analysis of this phenomenon in deepwater wells and its magnitude with the aid of mathematical modeling is goal of this study.
This technology could be highly productive for resolving ongoing tussle between ONGC and RIL over reservoir boundaries in KG-D6 reservoir by providing independent check of claims which geophysical data purports.
Project duration: NA
Xingru Wu (firstname.lastname@example.org), Ph.D., Project PI, Associate Professor at the University of Oklahoma (OU). His research interests include enhanced oil recovery, production and reservoir engineering, deepwater production and surveillance technologies, fluid phase behavior and flow assurance, and reservoir characterization. From 2005 through 2012, he worked in BP America as a reservoir engineer, and was involved in chemical flooding for enhanced oil recovery, nitrogen injection for gas condensate fields, and deepwater development and production in the Gulf of Mexico. He obtained his Ph.D. from the University of Texas at Austin in 2006 and M.Sc. from University of Alaska Fairbanks in 2002, and all degrees were on petroleum engineering. During his graduate study, he also worked at Alaska Oil & Gas Conservation Commission and Idaho National Laboratory. From 1997 through 2000, he worked at China National Offshore Oil Company as a petroleum engineer.
Priyank Srivastava (email@example.com), Graduate Student at the University Of Oklahoma (OU). His research interests include reservoir characterization, pressure transient analysis. From 2010 through 2014, he worked in Reliance Industries limited, India as a reservoir engineer and was involved in exploratory deepwater/on-land reservoir data acquisition from wireline formation testing, drill stem testing, core analysis and PVT experiments and preparation of these data for inputs to reservoir simulation models.