Pressure transient analysis (PTA) is one of the best tools to estimate critical well and reservoir parameters. Some of those are reservoir properties, reservoir size and shape (i.e. permeability, fracture properties, reservoir model, distance to boundaries, etc.), completion efficiency (i.e. skin, fracture performance…etc.), tubing performance (i.e. optimum tubing design and artificial lift requirements) and well (i.e. fracture performance, skin, etc.), and reservoir characterization (i.e. dual porosity, layered reservoir, composite, etc.). Therefore, proper interpretation of PTA is crucial to acquire critical parameters for field development and well optimization. Pressure transient analysis technology has improved over the time. However, real-life examples of pressure data to fit a given idealized model are often nonexistent. In addition, well test interpretation suffers from a variety of uncertainties that combined, to reduce the confidence of the analyses. This paper attempts to summarize the uncertainties associated with well test analysis, shows examples of pitfalls in well test analysis, and provides the methods that proposed to identify the uncertainties. The first phase of the project, a detailed analysis of several PTA interpretations collected from various oil and gas fields in Petroleum Development Oman (PDO), compiled and analyzed to identify the main areas of uncertainty. In the second phase of project, best practices for well test interpretation methods were developed to achieve a consistent interpretation approach across the company. In the third phase of project, five main sources causing an uncertainty on PTA interpretation were investigated, analyzed and demonstrated with relevant actual examples, as well as demonstrating the pitfalls in well test analysis. The study proposed and developed a six-step PTA interpretation Work Flow including QA/QC steps and the study identified five main uncertainty areas, developed techniques to evaluate each of these, and presented the pitfalls of each uncertainty. Those key uncertainty areas are: The uncertainty in reservoir properties The non-uniqueness of the PTA model responses The limitation of the data set The physical error in the pressure / rate data (including non-reservoir effects on pressure gauges response such as gauge drift) and the human effect The implications of well bore storage effect This document provides a summary and characterizes the five main sources of PTA uncertainties through actual data from PDO in the Sultanate of Oman. This document will also cover the best practices and workflow that have been developed & proposed in order to achieve a step change in the quality and reliability of the PTA interpretations. The implementations of the workflow are presented for a variety of reservoir types and field examples of its implications on well optimization and field developments will be shared.

In rich gas fields, condensate banking refers to the formation of condensate around the wellbore when the reservoir pressure drops below dew point. Condensate banking severely damages reservoir performance and results in loss of production capacity and ultimate recovery, especially for reservoirs with low permeability and high Condensate Gas Ratios. Understanding this process and quantifying its impact is therefore crucial to robust field development projects economics and effective well and reservoir management. The characterization of condensate banking is an integrated process where several reservoir parameters like fluid properties (PVT), geology (i.e. permeability), and rock properties (i.e. SCAL data) needs to be considered. Because of condensate banking, different flow regions with different characteristics are created within the reservoir where Pressure Transient Analysis (PTA) can identify these flow regions. This study attempts to characterize the condensate banking using PTA, shows examples of pitfalls in well test analysis of rich condensate fields and provides the methods proposed to identify condensation effect in PTA analysis. In order to detect, quantify and characterize condensate banking, a workflow was developed using PTA along with other field data (PVT/SCAL/production). The process to define this workflow includes; Conducting a review of critical parameters affecting the condensate banking process (PVT, SCAL, reservoir properties…. etc.), Collecting and interpreting all PTA’s (51) from 5 large gas condensate fields to understand the condensation process characteristics in terms of PTA diagnostics (i.e. determine the mobility change in the reservoir) Developing a novel integrated workflow and procedures for condensate banking characterization and quantification using Inflow Performance Curves (IPR). The key conclusions of integrated approach are follows; PVT (maximum condensate drop out), SCAL (Krg & Ng) and permeability plays a critical role for condensation effect Several PTA interpretations demonstrated that the expected 3 mobility regions associated to condensation effect may not able to be seen due to near wellbore & reservoir effects (i.e. wellbore storage, fraccing) that has been masking the condensation response, Even in case of hydraulically fracced well, condensation will still negatively affect the well performance. None of 5 field cases has shown any indication of a "capillary number effect" (i.e. velocity dependent relative permeability) IPR is proposed and used to quantify the impact of condensation drop out on production performance. An integrated workflow to detect, quantify and characterize condensate banking using PTA analysis has been developed and implemented in five large PDO gas condensate fields. This paper presents a novel systematic approach to achieve Condensate Banking Characterization Using PTA for gas condensate reservoirs as well as it provides several real cases to validate the workflow. Results can also contribute to a better reservoir management, quantification of the possible productivity losses of the well.

In this study development options are evaluated for a low permeability carbonate field located in the North of the Sultanate of Oman which has been on production since 1969. The dominant recovery mechanism is bottom aquifer water injection with an estimated recovery factor of around 50% till date. This study is aimed at testing the simultaneous injection concept and other water based EOR strategies for the field to present a range of options for future development. During the work several concepts were also designed to understand the impact of major heterogeneities on proposed recovery mechanisms, and to understand the role of gravitational forces on remaining oil distribution. Major findings of this work include the development of a range of recovery options for the field with incremental recovery ranging from 2% to 20% (Recovery Factor), improved understanding of the impact of heterogeneities and the role played by gravitational forces. The application of "Experimental Design" of simulation runs ensured capturing of the range of uncertainties in heterogeneities and provided a distribution of outcomes. Economics was evaluated for surfactant polymer flood and simultaneous injection concept to facilitate decision making.

Three years ago, People Survey scores on PDO Field Development Center (FDC) Diversity and Inclusion (62%) were well below Top Quartile & PDO ‘Petroleum Development Oman’ average. The FDC were determined to turn this around. D&I was made integral part of FDC's people program. The PDO D&I vision was firmly embraced by FDC and the statement is "to promote an inclusive workplace free from discrimination, bullying and harassment which celebrates diversity & provides all with an equal opportunity to succeed". A three prong FDC D&I strategy was developed and enforced by a newly energized FDC People Team, the 3a strategy is: awareness, absorb, action and engage staff. Raise AWAREness by: Prioritizing group learning events within FDC hosted by in-house subject experts, acknowledging key nation/religious events of employees in FDC, introductory talks on key processes and standards related to D&I. ABSORB is the soak & reflect mechanism driven by: voluntary circulation/rotation of the FDC Family Values Trophy to colleagues exhibiting one or more of D&Ivalues, ensure ADPs/coaching plans in place & perform people capability reviews twice a year. ACTION out the values through and engage the staff through: regular coaching/mentoring sessions, organizing FDC family day out event, Leader to Employees birthday acknowledgement gifts and increase staff Engagement through sustaining ‘Lunch with leader event, ‘leader Assist Day’ and introduction of ‘Talented People coffee corner event’. As a result of this structured approach to tackle the D&I performance. The Field Development Center achieved Top Quartile performance with noticeable improvements such as: 2017 FDC People Survey D&I score was 85% which is Top Quartile. (in comparison to 2014 score of 62%).High level of engagement (85% response rate for whole FDC on last People Survey).High level of energy in FDC community as acknowledged by line director and observed in technical and social events.

The Barik Deep clastic gas reservoir was discovered in 1991 and has been on production since 1994. It is a very rich gas condensate reservoir with initial Condensate to Gas Ratio (CGR) of 1100 m3/MMm3. With reservoir pressure dropping below dew point (428 bar vs. initial pressure of 478 bar), a huge volume of condensate has dropped-out inside the reservoir as confirmed by production data and the deterioration of well performance. As of 1/1/2018, the Barik Deep reservoir is developed with 29 gas producers out of which 7 wells are closed-in mainly due to liquid loading. The reservoir is currently producing above 2 MMm3/d of gas and ~400 m3/d of condensate and reservoir pressure is around 230 bars. An integrated subsurface-surface study was started in 2017 with the objectives ∘To propose an integrated plan for re-developing the Barik Deep∘To identify solutions to maximize recovery of the dropped-out condensate∘To resolve condensate banking issues and its impact on productivity∘To identify new technologies allowing to increase production, to increase the field recovery (gas and condensate) and to propose a maturation plan for these technologies. In a first phase of the project, a detailed analysis of all data collected over years of field development have been used to achieve a step enhancement in the understanding and characterization of the condensation process in Barik deep. In a second phase, the study involved the construction of compositional model capturing the physics of the condensation phenomena (i.e. very refined single well models) in order to assess various condensate recovery options. This effort supported the later building of full field simulation models to evaluate the impact of the most promising recovery techniques on recovery at field scale. This paper covers: The interdisciplinary novel data analysis workflow approach followed to determine the critical elements of the condensation process (PVT, SCAL, pressure depletion, reservoir properties,...etc)The quantification and characterization of condensation by using analytical methods (Pressure Transient Analysis, PVT and production data analysis)The evaluation of various condensate recovery options (CO2, N2, separator gas, water injection and cyclic gas injection) using very refined single well physics based modelsThe evaluation of condensate recovery options using full field models adapted from these physics based modelsThe economical evaluation of condensate recovery optionsThe proposed road map for maturation of the most promising options It is concluded from the conducted study work that out of the various injection fluid options considered, CO2 injection is likely to be the most favorable. Moreover, initial economical screening appear to be promising for CO2 injection.