Optimized Multi-Zone Dynamic Reservoir Evaluation in the Middle Caspian

2021 ◽  
Author(s):  
Sergey Shtun ◽  
Yermek Kaipov ◽  
Fanise Kamalov ◽  
Beibit Akbayev ◽  
Vlad Blinov
Keyword(s):  
Middle Part ◽  
Well Testing ◽  
Well Test ◽  
Reservoir Evaluation ◽  
Drilling Rig ◽  
Construction Design ◽  
Geological Conditions ◽  
Open Hole ◽  
Downhole Tool ◽  
Completion Fluids

Abstract Caspian offshore is reach for hydrocarbon reserves. The fields are made of multi-zone carbonate and sandstone reservoirs with significant variation of properties having high pressure (HP), high temperature (HT) and high H2S concentration in reservoir fluid. These challenges pose significant challenges to conduct the formation and multi-zone reservoir testing in a safe and informative manner. The dynamic reservoir evaluation program consists of formation pressure and its profile measurements, fluid pump-out for confirming the fluid type and sampling performed with wireline formation testers (FT) in open-hole and multi-zone well test for productivity estimation with drill-stem test (DST) designed for offshore environment with HP and high H2S. The project was planned and executed in an integrated manner, where the well construction design and selection of drilling and completion fluids has to improve the chance of success for FT and DST by taking into accound the downhole tool sizes and complex geological conditions. The open-hole formation testing and well testing in cased-hole were combined to provide enough information for characterizing multi-zone reservoirs by minimizing the drilling rig time. The well testing program was optimized in terms of number of zones for testing and necessity to acidize the reservoir based on formation testing data. The given methodolgy allowed to efficiently conduct the formation testing and well testing at two recently drilled offshore wells with multi-zone reservoirs. It was the first integrated dynamic reservoir evaluation project for such complex geological conditions in Middle part of Caspian offshore. This paper demonstrates the lessons learnt from two wells and offers the methodology for planning the evaluation for similar fields.

Application of Tubing Stem Test as Alternative Low-Cost Solution for Dynamic Reservoir Evaluation: Case Study from Appraisal Well in Offshore Malaysia

2021 ◽  
Author(s):  
Adhi Naharindra ◽  
Mohd Hisham Abd Hamid ◽  
A Ghafar A Halim ◽  
Sarah M Affandi ◽  
W M W Ibrahim ◽  
...  
Keyword(s):  
Produced Water ◽  
Low Cost ◽  
Integrated Approach ◽  
Design Stage ◽  
Test Design ◽  
Test Duration ◽  
Well Testing ◽  
Well Test ◽  
Testing Program ◽  
Reservoir Evaluation

Abstract This paper demonstrate a unique combination of techniques and equipment that enabled dynamic reservoir evaluation process using simplified Drill Stem Test (DST) string and completion accessories. The well testing was conducted on a shallow slanted offshore well, drilled into faulted reservoirs with multilayer and complex fluids environment. Key technical challenges to perform well testing includes designing a custom DST string to cater for the multilayer reservoir and articulating a surface well testing equipment that capable of efficient separation to ensure safe and environmental friendly disposal while having accurate flowrate measurements, to deliver good interpretable data given that the uncertainty and complexity of the formation and the well itself. During drilling campaign, contingency plan to mitigate against losses was implemented which had a significant impact on the well testing program. As such, uncertainty-based well test design and interpretation methodology was used to address this and to achieve well objectives. This involved numerical model analysis considering reservoir uncertainties and their interaction with each other, to identify which parameters can be interpret confidently and to indicate the test duration for the well testing program. Since the area is nearby to producing fields, several cases model based on reservoir pressure regime was also constructed during the design stage to tolerate flexibilities for the decision tree. The well testing was successfully conducted result from integrated approach to well test design and realtime data support throughout the operation along with innovative DST string design, customize completion accessories for multiple zones testing and adaptive intervention tools for highly deviated well. Matching with nearby wells were also conducted during monitoring to predict future pressure behaviour which allow for the duration of final build-up to be optimized. Given that Health, Safety and Environment (HSE) is the top of priority, an important aspect of the surface well testing package was the water treatment equipment to treat the produced water from reservoir before being discharge in order to guarantee safe environmental disposal. The well was successfully test at maximum flowrate 2,000bpd of oil and 20MMscf/d of gas with traces of produced water. Data gathered thru the Tubing Stem Test (TST) can used to interpret reservoir parameters and all the well testing objectives were successfully achieved despite the many challenges encountered during the drilling campaign and design stage. The end results may contradict traditional testing methods for pressure transient analysis, but hopefully this paper might create the opportunity to replicate TST as quick and effective reservoir evaluation in other parts of the world.

A Methodology that Enables Real Time Large Volume Reservoir Testing for Deeper Reservoir Targets in Old Wells Without Damaging the Existing Upper Reservoir Layers

2021 ◽  
Author(s):  
Ozgur Karacali ◽  
Sofiane Bellabiod ◽  
Bertrand Theuveny
Keyword(s):  
Real Time ◽  
Hydraulic Pressure ◽  
Well Testing ◽  
Well Test ◽  
Time Data ◽  
Noise Sources ◽  
Drilling Rig ◽  
Network Connection ◽  
Execution Phase ◽  
Downhole Measurements

Abstract Pressure transient testing has been significantly revamped and various types have been applied for numerous motives over the past decades. In this paper, a methodology and adapted technology have been discussed in detail for enabling downhole testing operations with existing open perforations above the test packer. This methodology enabled successful downhole testing operations where conventional annulus hydraulic pressure pulse system was ruled out for numerous reasons, such as existence of perforated zones above zone of interest and/or well integrity constraints. The proposed method is based on an acoustic, wireless, bi-directional downhole to surface communication telemetry system. The process utilizes acoustic signals to control downhole tools and transmits downhole measurements in real time through a secured network connection. The procedure used in this well testing methodology is proven successful in numerous well test operations for exploration and appraisal wells in Algeria. The continuously unfolding downhole data has enabled end users and stake holders to take actions and decisions that maximized the value gain while optimizing the test durations and drilling rig utilizations. The successful application of this proposed methodology has enabled parameter estimation during the execution phase of the well testing operations. Data measured in real time is coupled with reservoir engineering interpretation to ensure meaningful sub-surface evaluation. Wellbore dynamics and several other inherent noise sources have been successfully identified to avoid snags of misinterpretation. Wells needing stimulation treatment or longer clean-up durations to enhance the well to reservoir communication quality have been handily identified in real time. The methodology has proven hydrocarbon existence in unexplored layers while enabling incorporation of additional test objectives with further assessments of zones of interest. Real time data greatly reduced uncertainties in well behavior and assisted in informed-decision-making process to adapt well test programs in real time. All well testing objectives were achieved by addressing various challenges that are inherent to conventional memory mode downhole testing operations. The methodology presented will enable the downhole testing operations through drill stem testing (DST) in complex wellbore geometries where conventional well testing approaches were rendered unattainable. The proposed solutions will warrant downhole testing of previously un-appraised formation layers that are overlain by perforated producing reservoirs. The methodology is described in detail and systematically so that the procedure and learnings from Algerian hydrocarbon producing basins can be adapted and applied to other well tests elsewhere around the globe.

Use of Exclusion Zones in Mapping and Modeling Fracture Corridors

2010 ◽  
Vol 13 (04) ◽  
pp. 679-687 ◽  
Author(s):  
Sait I. Ozkaya
Keyword(s):  
Distance Matrix ◽  
Well Testing ◽  
Well Test ◽  
Exclusion Zone ◽  
Fracture Permeability ◽  
Reservoir Evaluation ◽  
Lost Circulation ◽  
Matrix Permeability ◽  
Water Breakthrough ◽  
Well Tests

Summary Fracture corridors are fault-related, subvertical, tabular fracture clusters that traverse the entire reservoir vertically and extend for several tens or hundreds of meters horizontally. Conductive fracture corridors may have significant permeability and may profoundly affect reservoir-flow dynamics. Therefore, it is important to map conductive fracture corridors deterministically for reservoir evaluation and well planning. Deterministic mapping of fracture corridors requires locating fracture corridors and assigning to them length, orientation, fluid conductivity, and connectivity. Estimation of orientation, length, and—especially—connectivity is a major challenge in fracture-corridor mapping. An exclusion zone is a region that cannot have a conductive fault or fracture corridor passing through. Borehole images, open-hole logs, flow profiles, and lost-circulation data can be used to identify horizontal wells with no fracture-corridor intersection. Well tests, production/injection history, Kh ratio (permeability times thickness) well-test/core ratio, first water arrival, and oil-column-thickness maps can be used to identify vertical “matrix” wells that do not intersect fracture corridors. Adjacent matrix wells may be surrounded by inferred exclusion zones. The confidence level of inferred exclusion zones depends on factors such as interwell distance, matrix permeability, width, orientation, and spacing of fracture corridors. Overlapping of exclusion zones from independent data sources such as well testing and oil-column thickness have higher confidence than non-overlapping zones. Only borehole images provide orientation and only well tests provide length of fracture corridors. In the absence of well testing and borehole imaging, exclusion zones provide constraints and aid both in locating fracture corridors and assigning them orientation and length. Perhaps the most significant contribution of exclusion zones to fracture-corridor mapping is in identifying interconnected and isolated fracture corridors. An interconnected network of fracture corridors may extend laterally for several kilometers as major fracture permeability pathways, which not only improve pressure support, bottom upsweep of oil, but also cause rapid water breakthrough.

A Back Allocation Methodology to Estimate the Real-Time Flow and Assist Production Monitoring

2021 ◽  
Author(s):  
Gabriela Chaves ◽  
Danielle Monteiro ◽  
Virgilio José Martins Ferreira
Keyword(s):  
Real Time ◽  
Input Data ◽  
Oil Field ◽  
Well Testing ◽  
Well Test ◽  
Time Data ◽  
Time Flow ◽  
Well Model ◽  
Operational Information ◽  
The Individual

Abstract Commingle production nodes are standard practice in the industry to combine multiple segments into one. This practice is adopted at the subsurface or surface to reduce costs, elements (e.g. pipes), and space. However, it leads to one problem: determine the rates of the single elements. This problem is recurrently solved in the platform scenario using the back allocation approach, where the total platform flowrate is used to obtain the individual wells’ flowrates. The wells’ flowrates are crucial to monitor, manage and make operational decisions in order to optimize field production. This work combined outflow (well and flowline) simulation, reservoir inflow, algorithms, and an optimization problem to calculate the wells’ flowrates and give a status about the current well state. Wells stated as unsuited indicates either the input data, the well model, or the well is behaving not as expected. The well status is valuable operational information that can be interpreted, for instance, to indicate the need for a new well testing, or as reliability rate for simulations run. The well flowrates are calculated considering three scenarios the probable, minimum and maximum. Real-time data is used as input data and production well test is used to tune and update well model and parameters routinely. The methodology was applied using a representative offshore oil field with 14 producing wells for two-years production time. The back allocation methodology showed robustness in all cases, labeling the wells properly, calculating the flowrates, and honoring the platform flowrate.

A Novel Well Test Data Analyzer and Process Optimizer Using Artificial Intelligence and Machine Learning Techniques

2021 ◽  
Author(s):  
Nagaraju Reddicharla ◽  
Subba Ramarao Rachapudi ◽  
Indra Utama ◽  
Furqan Ahmed Khan ◽  
Prabhker Reddy Vanam ◽  
...  
Keyword(s):  
Artificial Intelligence ◽  
Machine Learning ◽  
Real Time ◽  
Test Data ◽  
Oil Field ◽  
Well Testing ◽  
Well Test ◽  
Time Data ◽  
Real Time Data ◽  
Well Tests

Abstract Well testing is one of the vital process as part of reservoir performance monitoring. As field matures with increase in number of well stock, testing becomes tedious job in terms of resources (MPFM and test separators) and this affect the production quota delivery. In addition, the test data validation and approval follow a business process that needs up to 10 days before to accept or reject the well tests. The volume of well tests conducted were almost 10,000 and out of them around 10 To 15 % of tests were rejected statistically per year. The objective of the paper is to develop a methodology to reduce well test rejections and timely raising the flag for operator intervention to recommence the well test. This case study was applied in a mature field, which is producing for 40 years that has good volume of historical well test data is available. This paper discusses the development of a data driven Well test data analyzer and Optimizer supported by artificial intelligence (AI) for wells being tested using MPFM in two staged approach. The motivating idea is to ingest historical, real-time data, well model performance curve and prescribe the quality of the well test data to provide flag to operator on real time. The ML prediction results helps testing operations and can reduce the test acceptance turnaround timing drastically from 10 days to hours. In Second layer, an unsupervised model with historical data is helping to identify the parameters that affecting for rejection of the well test example duration of testing, choke size, GOR etc. The outcome from the modeling will be incorporated in updating the well test procedure and testing Philosophy. This approach is being under evaluation stage in one of the asset in ADNOC Onshore. The results are expected to be reducing the well test rejection by at least 5 % that further optimize the resources required and improve the back allocation process. Furthermore, real time flagging of the test Quality will help in reduction of validation cycle from 10 days hours to improve the well testing cycle process. This methodology improves integrated reservoir management compliance of well testing requirements in asset where resources are limited. This methodology is envisioned to be integrated with full field digital oil field Implementation. This is a novel approach to apply machine learning and artificial intelligence application to well testing. It maximizes the utilization of real-time data for creating advisory system that improve test data quality monitoring and timely decision-making to reduce the well test rejection.

scholarly journals Data Processing Method of Well Testing

2021 ◽  
Vol 134 (3) ◽  
pp. 35-38
Author(s):  
A. M. Svalov ◽  
Keyword(s):  
Boundary Condition ◽  
Asymptotic Expansion ◽  
Test Data ◽  
Traditional Method ◽  
Processing Method ◽  
Well Testing ◽  
Well Test ◽  
Conductivity Equation ◽  
Complete Asymptotic Expansion ◽  
Data Processing Method

Horner’s traditional method of processing well test data can be improved by a special transformation of the pressure curves, which reduces the time the converted curves reach the asymptotic regimes necessary for processing these data. In this case, to take into account the action of the «skin factor» and the effect of the wellbore, it is necessary to use a more complete asymptotic expansion of the exact solution of the conductivity equation at large values of time. At the same time, this method does not allow to completely eliminate the influence of the wellbore, since the used asymptotic expansion of the solution for small values of time is limited by the existence of a singular point, in the vicinity of which the asymptotic expansion ceases to be valid. To solve this problem, a new method of processing well test data is proposed, which allows completely eliminating the influence of the wellbore. The method is based on the introduction of a modified inflow function to the well, which includes a component of the boundary condition corresponding to the influence of the wellbore.

AN INTEGRATED PETROPHYSICAL CHARACTERIZATION OF A SILICICLASTIC TIGHT GAS RESERVOIRS IN NEUQUÉN BASIN, WESTERN ARGENTINA

2021 ◽  
Author(s):  
Nicolas Carrizo ◽  
◽  
Emiliano Santiago ◽  
Pablo Saldungaray ◽  
◽  
...  
Keyword(s):  
Water Saturation ◽  
Seismic Inversion ◽  
Tight Gas ◽  
Analysis Model ◽  
Drilling Rig ◽  
Irreducible Water Saturation ◽  
Neuquen Basin ◽  
Open Hole ◽  
Neuquén Basin ◽  
Pulsed Neutron

The Río Neuquén field is located thirteen miles north west of Neuquén city, between Neuquén and Río Negro provinces, Argentina. Historically it has been a conventional oil producer, but some years ago it was converted to a tight gas producer targeting deeper reservoirs. The targeted geological formations are Lajas, which is already a known tight gas producer in the Neuquén basin, and the less known overlaying Punta Rosada formation, which is the main objective of the current work. Punta Rosada presents a diverse lithology, including shaly intervals separating multiple stacked reservoirs that grade from fine-grained sandstones to conglomerates. The reservoir pressure can change from the normal hydrostatic gradient to up to 50% of overpressure, there is little evidence of movable water. The key well in this study has a comprehensive set of open hole logs, including NMR and pulsed-neutron spectroscopy data, and it is supported by a full core study over a 597ft section in Punta Rosada. Additionally, data from several offset wells were used, containing sidewall cores and complete sets of electrical logs. This allowed to develop rock-calibrated mineral models, adjusting the clay volume with X-ray diffraction data, porosity and permeability with confined core measurements, and link the logs interpretation to dominant pore throat radius models from MICP Purcell tests at 60,000 psi. Several water saturation models were tested attempting to adjust the irreducible water saturation with NMR and Purcell tests at reservoir conditions. As a result, three hydraulic units were defined and characterized, identifying a strong correlation with lithofacies observed in cores and image logs. A cluster analysis model allowed the propagation of the facies to the rest of the wells (50). Finally, lithofacies were distributed in a full-field 3D model, guided by an elastic seismic inversion. In the main key well, in addition to the open hole logs and core data, a cased hole pulsed neutron log (PNL) was also acquired , which was used to develop algorithms to generate synthetic pseudo open hole logs such as bulk density and resistivity, integrated with the spectroscopy mineralogical information and other PNL data to perform the petrophysical evaluation. This enables the option to evaluate wells in contingency situations where open hole logs are not possible or are too risky, and also in planned situations to replace the open hole data in infill wells, saving considerable drilling rig time to reduce costs during this field development phase. Additionally, the calibrated cased hole model can be used in old wells already drilled and cased in the Punta Rosada formation. This paper explores the integration of different core and log measurements and explains the development of rock-calibrated petrophysical and rock types models for open and cased hole logs addressing the characterization challenges found in tight gas sand reservoirs. The results of this study will be crucial to optimize the development of a new producing horizon in a mature field.

Pressure Analysis for Fractured Wells

1972 ◽  
Author(s):  
Alain C. Gringarten ◽  
Henry J. Ramey ◽  
R. Raghavan
Keyword(s):  
Skin Effect ◽  
Time Pressure ◽  
Physical Nature ◽  
Well Testing ◽  
Well Test ◽  
Time Data ◽  
Well Test Analysis ◽  
Test Analysis ◽  
Straight Line ◽  
Short Time

INTRODUCTION During the last few years, there has been an explosion of information in the field of well test analysis. Because of increased physical understanding of transient fluid flow, the entire pressure history of a well test can be analyzed, not just long-time data as in conventional analysis.! It is now often possible to specify the time of beginning of the correct semilog straight line and determine whether the correct straight line has been properly identified. It is also possible to identify wellbore storage effects and the nature of wellbore stimulation as to permeability improvement, or fracturing, and perform quantitative analyses of these effects. These benefits were brought about in the main by attempts to understand the short-time pressure data from well testing, data which were often classified as too complex for analysis. One recent study of short-time pressure behavior2 showed that it was important to specify the physical nature of the stimulation in consideration of stimulated well behavior. That is, statement of the van Everdingen-Hurst infinitesimal skin effect as negative was not sufficient to define short-time well behavior. For instance, acidized {but not acid fraced) and hydraulically fractured wells did not necessarily have the same behavior at early times, even though they might possess the same value of negative skin effect.

The Evolution of Green Completion in BP Khazzan Field

2021 ◽  
Author(s):  
Sultan Al Harrasi ◽  
Naren Jayawickramarajah ◽  
Taimur Al Shidhani ◽  
Daniel White ◽  
Mohamed Najwani
Keyword(s):  
Carbon Emissions ◽  
Environmentally Friendly ◽  
Pilot Project ◽  
Well Testing ◽  
Well Test ◽  
Safety Standards ◽  
Central Processing ◽  
The Usa ◽  
Reduce Emissions ◽  
Reduction Of Co2

Abstract Well Testing is the single largest contributor of carbon emissions during well operations and the industry's aspiration to reduce carbon emissions inspired the bp Oman team to identify innovative ways to reduce emissions from activities in the Khazzan field. Khazzan is characterized by tight reservoirs which requires hydraulic fracturing to release gas from the rock. After fracturing, the wells are tested/cleaned-up by flowing the well fluids and flaring the produced gas and condensate to the atmosphere. The testing removes contaminants – proppant, frac fluid, hydrogen sulphide – that could damage the downstream Central Processing Facility (CPF). ‘Green Completion’ was one of the opportunities that was identified by the bp's Oman team to remove these contaminants in an environmentally friendly manner. A Green Completion is a zero flaring concept – hydrocarbons produced during well test operations are ‘cleaned’ and then routed to processing facilities for export rather than being flared. This concept has been successfully utilized in bp's onshore US operations for over a decade. The team leveraged the experience from the USA, applying this technology to suit the conditions in Oman, but it was not simple nor straight forward. In the last two years, this process has been modified and reinvented for the operations in Oman as the company seeks to strategically reduce its global carbon footprint. In first half of 2018, the bp Wells team initiated a pilot project with the objective of developing Green Completion capability in the Khazzan field. This was the start of the journey to demonstrate bp's commitment to reducing greenhouse gas (CHG) emissions in a sustainable manner. Furthermore, bp's collaborative cross-functional aptitude allowed for expanding the use of Green Completions into the Ghazeer development, which enabled zero-emission well testing of newly drilled wells even before commissioning of the new pipeline infrastructure. Through this initiative, the region has reduced emissions and generated cash by selling the recovered hydrocarbons instead of flaring into the atmosphere during well testing operations. Since Q1 2019, the total reduction of CO2 emissions exceeded 240,000 tonnes of CO2 equivalent, which equates to taking circa 52,000 vehicles off the road for one year. The implementation of this environmentally friendly operation also adhered to strict safety standards. The rigid bp safety process guidelines ensured that all challenges and optimization opportunities were fulfilled in a safe manner. The purpose of this paper is to detail how the team pushed the technical envelope to introduce this technology and share the journey entailing extensive cross-disciplinary cooperation amongst operations, subsurface and wells teams to fulfill the zero emissions objective.

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