Insights into Khuff Oil Rim Development in Sultanate of Oman from Extensive Drilling and Well Testing Operations

2021 ◽  
Author(s):  
Tingting Zhang ◽  
Arun Kumar ◽  
Rashid Al Maskari ◽  
Maryam Musalami ◽  
Sumaiya Habsi
Keyword(s):  
Management Plan ◽  
Productivity Index ◽  
Well Testing ◽  
Flow Profile ◽  
Well Test ◽  
Sultanate Of Oman ◽  
Full Field ◽  
Associated Gas ◽  
Field Development ◽  
Rock Types

Abstract The Yibal Khuff project is a mixed oil-rims, associated gas, and non-associated gas development in highly fractured tight carbonate reservoirs. Rock types and fractures vary widely with significant contribution to flow. In the east segment of the field, 22 horizontal oil producers targeting K2 reservoir have been pre-drilled and tested extensively. The integration of well logs, borehole image data (BHI), well test data and production logs provide key insights into reservoir productivity and the development of a robust well and reservoir management plan, ready for start-up of the field in 2021. A log-based approach was used to classify the reservoir into three main rock types (RRT). Fractures were classified, and high impact fractures were identified. Reservoir flow profile based on noise and temperature logs was established and used in combination with fracture data and cement bond logs in understanding flow conformance and behind casing flow. A large variation in productivity index has been observed, from tight to highly productive wells. Different ways have been explored to establish the link between productivity index, fracture production, and matrix production by rock types. This is the first full field development in the Khuff formation in Sultanate of Oman. The results will benefit a wider audience. A holistic approach was taken to explore the link between well deliverability and nature of a complex geology. The outcome is a robust operating envelope and well, reservoir and facilities management (WRFM) plan, clearly driven by understanding of subsurface risk and opportunities.

Implications of accurate geomechanical modelling and systematic core testing for sanding evaluation and sand control decisions – a case study from Perth Basin

2020 ◽  
Vol 60 (1) ◽  
pp. 267
Author(s):  
Sadegh Asadi ◽  
Abbas Khaksar ◽  
Mark Fabian ◽  
Roger Xiang ◽  
David N. Dewhurst ◽  
...  
Keyword(s):  
Management Strategies ◽  
Mechanical Tests ◽  
Well Test ◽  
Sand Production ◽  
Gas Field ◽  
Stress Regime ◽  
Full Field ◽  
Field Development ◽  
Sand Control ◽  
Rock Mechanical Properties

Accurate knowledge of in-situ stresses and rock mechanical properties are required for a reliable sanding risk evaluation. This paper shows an example, from the Waitsia Gas Field in the northern Perth Basin, where a robust well centric geomechanical model is calibrated with field data and laboratory rock mechanical tests. The analysis revealed subtle variations from the regional stress regime for the target reservoir with significant implications for sanding tendency and sand management strategies. An initial evaluation using a non-calibrated stress model indicated low sanding risks under both initial and depleted pressure conditions. However, the revised sanding evaluation calibrated with well test observations indicated considerable sanding risk after 500 psi of pressure depletion. The sanding rate is expected to increase with further depletion, requiring well intervention for existing producers and active sand control for newly drilled wells that are cased and perforated. This analysis indicated negligible field life sanding risk for vertical and low-angle wells if completed open hole. The results are used for sand management in existing wells and completion decisions for future wells. A combination of passive surface handling and downhole sand control methods are considered on a well-by-well basis. Existing producers are currently monitored for sand production using acoustic detectors. For full field development, sand catchers will also be installed as required to ensure sand production is quantified and managed.

scholarly journals EPS Conceptual Design for GoM Deepwater Fields

2010 ◽  
Author(s):  
Michael Choi ◽  
Andrew Kilner ◽  
Hayden Marcollo ◽  
Tim Withall ◽  
Chris Carra ◽  
...  
Keyword(s):  
Conceptual Design ◽  
Oil And Gas ◽  
Cost Effective ◽  
Test System ◽  
Well Test ◽  
Well Performance ◽  
Compressed Natural Gas ◽  
Full Field ◽  
Field Development ◽  
Early Production

To avoid making billion dollar mistakes, operators with discoveries in deepwater (∼3,000m) Gulf of Mexico (GoM) need dependable well performance, reservoir response and fluid data to guide full-field development decisions. Recognizing this need, the DeepStar consortium developed a conceptual design for an Early Production System (EPS) that will serve as a mobile well test system that is safe, environmentally friendly and cost-effective. The EPS is a dynamically positioned (DP) Floating, Production, Storage and Offloading (FPSO) vessel with a bundled top tensioned riser having quick emergency disconnect capability. Both oil and gas are processed onboard and exported by shuttle tankers to local markets. Oil is stored and offloaded using standard FPSO techniques, while the gas is exported as Compressed Natural Gas (CNG). This paper summarizes the technologies, regulatory acceptance, and business model that will make the DeepStar EPS a reality. Paper published with permission.

Bringing Flexibility and Automation to Well Testing Operations Through Wireless Telemetry - Case Study

2021 ◽  
Author(s):  
Elias Temer ◽  
Deiveindran Subramaniam ◽  
Yermek Kaipov ◽  
Carlos Merino ◽  
Vladimirovich Latvin ◽  
...  
Keyword(s):  
Real Time ◽  
Reservoir Characterization ◽  
Time Window ◽  
Weather Conditions ◽  
Development Planning ◽  
Testing Time ◽  
Well Testing ◽  
Well Test ◽  
Real Time Control ◽  
Field Development

Abstract Dynamic reservoir data are a key driver for operators to meet the forecasted production investments of their fields. However, many challenges during well testing, such as reduced exploration and capex budgets, complex geologic structures, and inclement weather conditions that reduce the well testing time window can prevent them from gathering critical reservoir characterization data needed to make more informed field development planning decisions. To overcome these challenges, a live, downhole reservoir testing platform enabled the most representative reservoir information in real time and connected more zones of interest in a single run for appraisal wells in the Sea of Okhotsk, Russia. This paper describes the test requirements, the prejob planning, and automated execution of wirelessly enabled operations that led to the successful completion of the well test campaign in very hostile conditions, a remote area, and restricted period. The use of a telemetry system to well testing in seven zones enabled real-time control of critical downhole equipment and acquired data at surface, which in turn was transmitted to the operator's office in town in real time. Various operation examples will be discussed to demonstrate how automated data acquisition and downhole operations control has been used to optimize operations by both the service company and the operator.

Integrated Hydraulic Fracturing and Well-Test Data Analytics using R

2022 ◽  
Author(s):  
Nico A. M. Vogelij
Keyword(s):  
Hydraulic Fracturing ◽  
Data Analytics ◽  
Numerical Algorithms ◽  
Well Testing ◽  
Tight Gas ◽  
Well Test ◽  
Sultanate Of Oman ◽  
Well Performance ◽  
Consistent Manner ◽  
Testing Practices

1. Abstract Various datasets are generated during hydraulic fracturing, flowback- and well-testing operations, which require consistent integration to lead to high-quality well performance interpretations. An automated digital workflow has been created to integrate and analyze the data in a consistent manner using the open-source programming language R. This paper describes the workflow, and it explains how it automatically generates well performance models and how it analyzes raw diagnostic fracture injection test (DFIT) data using numerical algorithms and Machine Learning. This workflow is successfully applied in a concession area located in the center of the Sultanate of Oman, where to date a total of 25+ tight gas wells are drilled, hydraulically fractured and well-tested. It resulted in an automated and standardized way of working, which enabled identifying trends leading to improved hydraulic fracturing and well-testing practices.

The Selection and Optimum Well Testing Practices to Achieve Zero Flaring & Venting in Malaysian Water for a Petronas Field Development

2021 ◽  
Author(s):  
Adhi Naharindra ◽  
Zalina Ali ◽  
Nik Fazril Ain Sapi’an ◽  
Latief Riyanto ◽  
Fuziana Tusimin ◽  
...  
Keyword(s):  
Environmental Impact ◽  
Oil And Gas ◽  
Oil Field ◽  
Testing System ◽  
Well Testing ◽  
Well Test ◽  
Flow Lines ◽  
Field Development ◽  
Well Completion ◽  
Production Facilities

Abstract Increased HSE concerns and global economic efficiency from well testing activities especially on its environmental impact have left several oil and gas industries’ facing critical challenges to develop and monetize oil reserves. Some of these challenges include handling well effluents from well test unloading operations after well completion with high contaminants such as H2S and CO2 which will exacerbate environmental impact to safety, pollution, and oil spill risks. In addition, mitigation to environmental impact will be constrained to limited deck space and topside loads for offshore wellhead facilities and eventually restricts the footprint of well test unloading equipment. The scope of the paper is to examine the evolution of well deliverability testing from conventional well test facilities’ flaring practices to contemporary smokeless and zero flaring operations applied in a giant sand stones oil field in Malaysian water, which is surrounded by a world class environmentally protected marine and coastal ecosystem. The zero-flaring approach allows a demonstration of the safety & emission reduction, cost saving, technical viability, and economic benefits over traditional flaring techniques for 20 to 30 well testing during the life of field. Previous wells clean up method require flaring of oil and gas before the production facilities and flow lines were operational.commissioned. The application of environment friendly well testing system using the completed flow lines and production facilities enable zero-flaring option to be technically and economically viable. Zero-flaring well testing system provides several attractive benefits, with potential reduction in flaring equivalent of ±1000 barrels of oil, pollution avoidance, 40 - 50% schedule reduction and over 40% reduction in total project costs for the field development..

Floating early production systems

2011 ◽  
Vol 51 (2) ◽  
pp. 671
Author(s):  
Hayden Marcollo ◽  
Christopher Carra
Keyword(s):  
Deep Water ◽  
Oil And Gas ◽  
Production Systems ◽  
Rate Capability ◽  
Full Field ◽  
Associated Gas ◽  
Field Development ◽  
Sea Bottom ◽  
Early Production ◽  
High Level

Floating early production systems (FEPS) are becoming more important to the successful exploitation of Australia's deep water oil and gas. Importantly, FEPS help oil and gas operators reduce deep water full field development risk, as uncertainty in the reservoir characteristics are reduced by obtaining dynamic data (that is, partially producing some of the reservoir). This paper will present a review of existing FEPS that are now in use or have previously been in use worldwide and will discuss where they are headed in the future. The paper focuses on: The selection of the floating and subsea-vessel, mooring, riser, mechanical connection, etcetera; Technology presently available; and, Addressing the requirements in situations where new floating and subsea technology is needed. The qualification limits of existing technology will be discussed in the context of what systems are ready and off-the-shelf for operators to make use of now. The choice of appropriate FEPS will be discussed as a function of: proximity to pipeline infrastructure, potential production rate, capability to re-inject associated gas, prevailing variation in year-round environmental conditions, waterdepth, and, geotechnical description of sea bottom. A high level conceptual case study showing typical costs for the implementation of a deep water FEPS will be presented as a way of understanding the potential upside and downside exposure for an operator considering undertaking a deep water FEPS program.

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.

Revision of Pressure Transient Analysis in Mature Condensate-Rich Tight Gas Fields in Sultanate of Oman

2022 ◽  
Author(s):  
Ahmed Elsayed Hegazy ◽  
Mohammed Rashdi
Keyword(s):  
Transient Analysis ◽  
Horizontal Wells ◽  
Development Planning ◽  
Reservoir Modeling ◽  
Sultanate Of Oman ◽  
Pressure Transient Analysis ◽  
Pressure Transient ◽  
Full Field ◽  
Gas Fields ◽  
Half Length

Abstract Pressure transient analysis (PTA) has been used as one of the important reservoir surveillance tools for tight condensate-rich gas fields in Sultanate of Oman. The main objectives of PTA in those fields were to define the dynamic permeability of such tight formations, to define actual total Skin factors for such heavily fractured wells, and to assess impairment due to condensate banking around wellbores. After long production, more objectives became also necessary like assessing impairment due to poor clean-up of fractures placed in depleted layers, assessing newly proposed Massive fracturing strategy, assessing well-design and fracture strategies of newly drilled Horizontal wells, targeting the un-depleted tight layers, and impairment due to halite scaling. Therefore, the main objective of this paper is to address all the above complications to improve well and reservoir modeling for better development planning. In order to realize most of the above objectives, about 21 PTA acquisitions have been done in one of the mature gas fields in Oman, developed by more than 200 fractured wells, and on production for 25 years. In this study, an extensive PTA revision was done to address main issues of this field. Most of the actual fracture dynamic parameters (i.e. frac half-length, frac width, frac conductivity, etc.) have been estimated and compared with designed parameters. In addition, overall wells fracturing responses have been defined, categorized into strong and weak frac performances, proposing suitable interpretation and modeling workflow for each case. In this study, more reasonable permeability values have been estimated for individual layers, improving the dynamic modeling significantly. In addition, it is found that late hook-up of fractured wells leads to very poor fractures clean out in pressure-depleted layers, causing the weak frac performance. In addition, the actual frac parameters (i.e. frac-half-length) found to be much lower than designed/expected before implementation. This helped to improve well and fracturing design and implementation for next vertical and horizontal wells, improving their performances. All the observed PTA responses (fracturing, condensate-banking, Halite-scaling, wells interference) have been matched and proved using sophisticated single and sector numerical simulation models, which have been incorporated into full-field models, causing significant improvements in field production forecasts and field development planning (FDP).

Sign in / Sign up

Export Citation Format

Share Document