bluuebunny/crossref_metadata_2025 huggingface dataset:
Turbulence Effects during Transient and Boundary-Dominated Flow in Reservoirs with Storage and Skin Damage with Applicability in Gas Hydrate Reservoirs: Class 1&2 and Normally Pressured Class 3
Authors: Kome Melvin N. , Amro Mohd
Published: February 2017

Reservoir characterization with well test analysis has seen huge improvements in the last decade. Although the challenges are huge, especially with unconventional reservoirs, more still has to be done with respect to reducing the non-uniqueness of the reservoir responses by deriving representative conceptual models. As an effort to improve on the accuracy of well test analysis, a well test model accounting for both transient and boundary dominated turbulent effects was developed, which will reduce erroneous estimation of formation permeability, especially for analysis of single well tests.

The turbulence effects in well test analysis are known to be accounted for in the ideal reservoir responses by simply superposing the turbulent part of the Forchheimer-Darcy equation in the steady state form. Other numerical methods have been addressed in the past like in the works of [1] and [2]. As of now, very little has been done to analytically characterize turbulence (Non-Darcy) effects in well test models from early to late time periods of reservoir flow.

The model developed in this work utilizes the conventional Forchheimer-Darcy model with a linearization method for deriving the general solution, by adopting the effective fluid velocity in the diffusivity equation, which is a function of the Forchheimer number. By reapplying the Forchheimer equation to the boundary conditions, we obtain a solution to the model. Damage skin here is addressed based on the composite reservoir model.

The model clearly shows that by considering the transient turbulence effects, even the derivatives during IARF and boundary flow are turbulent dominated and a function of the flow rate for pressure transient analysis (PTA). Hence the permeability derived from the derivative during IARF is a Non-Darcy permeability. The conventional method applied in deducing the damage skin from the non-Darcy skin is actually applicable to the permeability derived during IARF. The errors made in the past with respect to deriving permeability, the turbulent skin and subsequently the damage skin for reservoirs with turbulent flow during PTA will be highlighted.

The model shows clearly the effects of analyzing data in transient flow period and the possible errors made in the past with respect to permeability and damage skin. The error which however become insignificant during boundary dominated flow.
Combination of Array Dielectric Measurements and Nuclear Magnetic Resonance Data for Better Fluid Identification in the Urho Tight Conglomerate Oil Reservoir, Junggar Basin
Authors: Youguo Sun , Cheng Liang , Hanlin Liu , Xin Meng , Qing Wang , Jinlong Wu , Xianran Zhao , Ghosh Krishnendu
Published: February 2017

The Upper Urho Sandy Conglomerate Reservoir in Xinjiang oilfield features complex lithology, low porosity and low permeability, and a majority of secondary pores with poor connectivity. Due to those characteristics, the log responses are complicated and it is difficult to determine the oil saturation with conventional resistivity method. In this paper, the reservoir heterogeneity was studied based on image logs and nuclear magnetic data, and oil saturation was calculated using array dielectric data. An integrated reservoir evaluation and fluid identification approach was established and applied in five wells located in different fault blocks. The testing results from four of them have proved the effectiveness of the proposed method. This is the first time to use array dielectric tool to identify fluid type in conglomerate reservoir with volcanic matters, and it has been introduced to similar oil reservoirs in other oilfields, which also obtained good application effect.
Bridging Skill Gaps — Leading By Example
Authors: Dahaini Faisal , Davies Robert P.
Published: February 2017

This paper ranges from company programs to "on-the-job" field reinforcement of attitudinal mindset changes in personnel. Operational excellence (OE) leverages our reputation for safety and efficiency, and builds on processes that exhibit excellence in parts of the business to ensure all aspects are standardized for all company organizations. This document focuses on enabling OE through immersing employees in innovative standards, and rewarding individuals for using concepts with opportunities for advancement based on performance rather than retention.

The Drilling and Workover Organization (D&WO) is tasked with shifting the attention of workforce personnel to the development of local talent. Rig site meetings enhance the front-line workforce personnel on how OE will make their lives safer, more educational, and more productive, and provide more varied career opportunities. Workplace personnel with a human resource, i.e., Knowledge Transfer Subject Matter Expert (KT SME), assigned to a 28/28 schedule for reminding, encouraging, and providing training that increases the workforce's chances of career progression is an effective means of ensuring consistency by using OE as a tool for achieving successful, long lasting careers.

Results of intellectually planned changes in approach to industry practices requires measureable objectives. These quantifiable items have to be backed by hard data. For data to be accurate there has to be a means of recording, comparing, and determining whether competencies indicate an improvement to existing company standards. Universal Recourse Locators were developed by KT internally for this purpose and utilized via the company's intranet. Local Talent Development utilizes the results of data gathered by the Knowledge Transfer Management System (KTMS) to provide management with tools necessary for making decisions about the workforce. The program is controlled by KT SMEs that provide the dynamic data entry of the competencies of workforce employees to the KTMS from remote rig sites. The KT SMEs are available in the field using "hands-on" techniques that follow OE and KT competency maps (CMap) and competency steps for each rig, craft, and employee. The KT SME transfers his OE expertise to the workforce at the rig site. KT SMEs use OE, competencies, company safety regulations, and awareness for the protection of company equipment and KT to employees consistent with their priority training objectives.

The company allowed the KT Group to innovate by providing free space in developing management approved objectives for recording of data for aiding workforce decision making, i.e., KTMS. The KTMS is a unique tool in illustrating dynamic beginnings and presenting the competency progress of 338 men. The tool divides their competencies into four parts, which allow personnel to be judged on what they are competent in and on what they need to spend time for self-development.
Will it or won't it flow!! - A Novel Approach to Understand and Characterize the Fractures for Fluid Conductivity in Basement Reservoirs
Authors: Augustine M. , Murthy A. V. , Boindala Amitha , Bahuguna Somesh , Talreja Rahul , Pattanaik Sambit , Kalita Deepika , Das Sourav
Published: February 2017

Madanam field in Cauvery basin in the east coast of India, has fractured gneissic basement. As exploration focus moved to unconventional reservoirs, the gneissic basement of Madanam was seen as a potential reservoir. However, ambiguity existed about the fluid flow through the basement. For example, in Madanam field, one well (well A) flowed whereas another well (well B) located 8.5 km away had minor flow from the basement reservoir that lasted 2 days. The main purpose of this study was to find possible reasons for this anomalous behavior. This study was conducted by integrating sonic and image measurements with a geomechanics workflow to identify critically stressed open fractures. Further, this work aims to provide a fit-for-purpose solution to optimize and prioritize testing zone selection in near real time.
Reservoir Geomechanics in Carbonates
Authors: Hamid Osman , Omair Ahmed , Guizada Pablo
Published: February 2017

Development of formations with stress sensitivity is raising awareness that Geomechanics is a vital aspect of future management. Understanding geomechanical behavior is becoming more and more important for the petroleum industry. It has been reported by many authors (e.g. Herwanger and Koutsableloulis 2011) that, significant changes in pore pressure (ΔP) due to depletion or injection in weak formation might lead to increase in effective stress, compaction, reduction in porosity and permeability, casing deformation, failure and subsidence, challenges in fracturing the formation, closing and opening pre-existing fracture fault re-activation and bedding parallel slippage. The deformations affect the apparent time-shifts from seismic surveys of under- and overburden.

The changes in stresses/strain affect the formation of interest as well as the overburden layers and directly affect all operations such as drilling, completion and production strategies because of permeability reduction. Stress affects nearly all petrophysical properties. Compaction, shear casing and well damage, cap-rock integrity, fault reactivation and sand production can occur during Formation depletion.

A coupled Finite Element approach is taken for modeling Geomechanical effects induced by production/injection and the cycle dependence between pore fluid flow and def of the tight carbonate, which impact hydrocarbon production. Using Visage, the finite element analysis model for the geomechanical analysis and the fluid flow simulator Eclipse for ΔP determination, this work looks at ΔP – stress coupling, which has significant implications for porosity/permeability reduction.

To address these issues, a conceptual two-way coupling model has been constructed using Finite Element method and Eclipse; the results show that, change in pressure has some implications on porosity and pereability. Both 3D and 4D Geomechanical models were developed that describe the state of stresses in the weak formation and overburden as well as changes in stress over time with either production or injection.
Predicting Heat Flow and Determining Crustal Type Based on Integrated Interpretation of Seismic, Gravity and Magnetic Data in the Offshore Jazan Area, Southern Red Sea
Authors: Salem Ahmed , Hussein Walid , Ion Dumitru , Bruno Priscilla Silva , Wu Schuman , Borsato Ronald
Published: February 2017

Predicting heat flow in constrain modeling of a petroleum system in the Red Sea is a significant exploration challenge. In this study, we developed an integrated workflow to utilize seismic, magnetic and gravity data in the offshore Jazan area of the Red Sea to build a crustal model and to identify crustal type. Depth to Curie temperature was estimated from magnetic data and used together with thermal properties of the rocks to predict present-day heat flow for the interpreted crustal model. The predicted heat flow shows a generally increasing trend toward the rift axis due to an elevated asthenosphere boundary that is consistent with a thinned crust model. The model of thinning continental lithosphere and predicted heat flow derived from the integrated workflow provides valuable constraints to reduce the uncertainties in basin modeling.
Tight Hydrocarbon Exploration Potential in Central Onshore Abu Dhabi Giant Field
Authors: Taher Ahmed , Al Aryani Fatima , Al Zaabi Mohamed R.
Published: February 2017

As the super-giant fields in the area continue to produce their hydrocarbon resources, there is a natural decline in production as the easy to access resources are going to be depleted in a few decades.

Finding additional oil and gas resources to replace the produced hydrocarbon is representing major challenge. The hydrocarbon saturated tight layers, found in the super-giant onshore field, could represent an example for finding additional hydrocarbon volume that accumulated in a difficult trap style. The central onshore field tight layers were found in the successions extended from the Lower Cretaceous, Thamama Group down into the Upper Permian Khuff formation.

The high hydrocarbon saturation found in the Thamama tight layers was previously interpreted as residual oil left behind during the vertical oil migration from the Upper Jurassic Hanifa source rock into the Thamama reservoirs. However, the current charge model assumes a lateral westward hydrocarbon migration from east onshore Abu Dhabi through the Thamama reservoirs and towards the major Abu Dhabi central onshore fields. The charge filling started from the top of the structure and down into the spill point and filled both, the porous and tight layers (figure 3). The differences are in the reservoir properties, which by using the technology improvement in the horizontal drilling and hydraulic fracturing, the tight zones hopefully will produce a significant volume of hydrocarbon.

The Lower Jurassic and Triassic formations were not previously considered as exploration objectives. Only one well penetrated these formations and it was targeting the deeper Khuff reservoirs. Several attempts were made to test some of these formations, but they were found to be completely tight. The water recovered from such testings was most probably drilling fluids.

The Khuff reservoirs high gas shows while drilling, the high hydrocarbon saturation of its interpreted logs do not match its negative testing results. The cause of failure is most probably related to the formation damage and the classical tools and methods used in the production test. In addition to that, the cement jobs were not quite successful, which will allow for the water leakage behind the casing.
Development and Evaluation of Foam-Based Conformance Control for a High Salinity and High Temperature Carbonate
Authors: Fuseni Alhasan B. , Julaih Ali H. , Al-Aseeri Abdulrahman A. , AlSofi Abdulkareem M.
Published: February 2017

Carbonate reservoirs’ extreme heterogeneity in the form of fracture corridors and super-permeability thief zones present challenges to the efficient sweep of oil in both secondary and tertiary recovery operations. In such reservoirs, conformance control is crucial to ensure injected water and any EOR chemicals optimally contact the remaining oil with minimal throughput. Foam-based conformance control is a relatively new technology especially its use for in-depth diversion in high salinity high temperature conditions. In this work, a laboratory study was conducted to develop and evaluate a foam-based conformance control technology for application in a high salinity and high temperature carbonate. Foaming agents were first screened for their suitability with regard to reservoir temperature and salinity where properties such as foamability and foam stability were measured. The best performing surfactants were then used to study the mobility reduction across a core composite at reservoir temperature and pressure. Foam stability and decay were also investigated in those permeability reduction experiments. Brine and crude oil were injected after foam formation and pressure drops and sustainability of mobility reduction were quantified. The improvement in reservoir contact and hence oil recovery were examined by oil displacement experiments conducted in specially prepared heterogeneous composites.

For the studied conditions of high salinity and high temperature, foaming agents of the amphoteric family as well as a special blend were found suitable in terms of salt tolerance and foam stability. The mobility reduction due to foam was 12 times without oil and 6 times in the presence of oil. Oil recovery improvement with foam application was also found to be significant. These results demonstrate the potential of the identified foam system and its favorable impact on sweep efficiency despite the harsh salinity and temperature conditions of the studied carbonate reservoir.
Progressive-Recursive Self-Organizing Maps PR-SOM for Identifying Potential Drilling Target Areas
Authors: Dossary Mubarak , Al-Turki Ali , Harbi Badr , Faleh Abdulhamid
Published: February 2017

Identifying potential productive reservoir units for infill drilling is a major challenge in developing giant fields in order to meet production targets and extend plateau. A common practice in identifying potential drilling locations is using oil saturation from production logs or near-by wells performance. Literature already recommended combining static and dynamic parameters from reservoir models (geological or numerical) to calculate cell performance indices such as Reservoir Opportunity Index (ROI) or Simulation Opportunity Index (SOI). It is difficult for those methodologies to provide volumetric representation of the hydrocarbons in potential areas since they do not specify the details of the clustering mechanism of similarly performing cells. The proposed algorithm allows the reservoir engineer to, progressively and recursively, define hydrocarbon sweet spots areas.

In this work, progressive-recursive self-organizing maps (PR-SOM) is developed and tested on a carbonate reservoir model. PR-SOM is an unsupervised artificial intelligence neural network algorithm that classifies the simulation grid cells into potential drilling targets by using a progressive list of dynamic or static reservoir parameters to identify similarly "good" contiguous regions. This is achieved by applying SOM on geomodels based on relative permeability, fluid saturation, pressure, and displacing fluid influx in the first iteration. The second iteration, PR-SOM explores the already selected regions and applies SOM on mobile and immobile hydrocarbons. The last iteration recursively applies PR-SOM to identify areas away from existing wells on the already defined regions from last iteration. The algorithm allows further definition of sweet spots based on more parameters and will further increase the potential value of the classified regions.

PR-SOM was applied to a carbonate reservoir with the objective of identifying un-swept areas as potential candidates for infill drilling. To compare the resulting potential target regions, an implementation of sweet spot identification algorithm and conventional approaches were applied on the same field. The results show that PR-SOM generated more accurate and conservative regions reducing the risks and increasing the confidence in the designated regions. In addition to obtaining more accurate clustering results, using PR-SOM allows extending the search to increase the value of required targets whereas previous work has to adhere to the original selected parameters (static or dynamic) for region identification and selection.
Geological Models Comparison and Selection for Multi-layered Sandstone Reservoirs
Authors: Yong Li , Chunxia Jia , Benbiao Song , Baozhu Li , Yixiang Zhu , Qihao Qian , Chenji Wei
Published: February 2017

The inter-zone and intra-zone heterogeneity are the key issues for multi-layered sandstone reservoirs. While usually lots of equal probability fine geological models which match all constrained data can be built, and how to select the representative models for reservoir simulation is a problem. This paper presents how to compare different geological models and select representative models in detail for a multi-layered sandstone reservoir in Middle East.

Through detailed geological characterization and dynamic description, different equal-probability geological models are built. And through geological check and analysis on each model, a preliminary comparison and understanding of each model are conducted, including gridding method comparison, vertical and lateral connectivity comparison etc. Then based on streamline numerical simulation, performance of each zone, each well for each model are compared in detail. Most performance are as we expected, but some are outliers. Through detailed analysis, the fundamental reasons for performance difference and major factors impacting on reservoir performance are determined. Finally, three models are selected for next reservoir simulation.

Take K reservoir in Middle East for example, it is a large multi-layered sandstone reservoir of deltaic environment. K is influenced by fluvial, tide and wave, which results in great variations of sand bodies’ distribution, reservoir quality and connectivity. Nine equal-probability geocellular models of K reservoir are built, which use three different lateral connectivity patterns with three vertical gridding approaches representing different vertical connectivity during modelling. Model expected performance are firstly determined based on geological analysis of each model. Then, based on streamline simulation, performance comparison including water cut variation, recovery, etc. are conducted to all models for the zone level, member level and model level. Three models are finally selected which represent Upside model with good lateral and vertical connectivity, Expected model with medium connectivity and Downside model with poor connectivity respectively. These models can be used for reservoir development strategy and risk management study.

This paper offers a case study of geological model comparison and selection mainly based on streamline simulation for a multi-layered sandstone reservoir. It ensures the selected models have reservoir heterogeneity correctly characterized, and the selected models are then used for the next development strategy and risk management study. It also provides a methodology and reference case for engineers to study on other similar reservoirs.
First Five-Zone Smart Completion Technology Deployment in ERC Well
Authors: Zahrani A. M. , Amri M. A. , Yateem K. S. , Mendes G. D.
Published: February 2017

The global demand for energy is on the rise daily, this puts a heavy burden on Oil and Gas companies as the drilling and production challenges are increasing. Efficient and cost-effective solutions are always sought. Drilling multilateral horizontal wells is considered as one of the optimum solutions to maximize recovery with minimal cost in terms of wells drilled. The production from multilateral wells imposes it is own challenges, such as flow distribution and contribution from laterals. Installing smart completions in multilateral wells was a huge breakthrough and revolutionized the industry. The idea behind smart completions is to continuously monitor and control the production from each lateral individually. With the current configuration of downhole packers, the number of interval control valves (ICV) installed per well is four at most, which limits the number of effective laterals in a well. Considering the primary objective of minimizing drawdown and hence maximizing sweep efficiency from each well, it was studied and simulated that some reservoir compartments have an optimum number of five laterals, which makes it complicated to control and optimize the production.

This paper exhibits the deployment of the first "5-Zone Smart Completion" technology in a five lateral well, to control the flow contribution from each lateral. Each completion section installed is comprised of a gauge carrier, a hydraulic flow control valve, a packer with feed-through ports and a sub to accommodate and secure control line splices. The technology enabled the control of the flow rate from five different zones and the measurement of pressure and temperature from each compartment. The completion design included another two pressure and temperature sensors downstream of the flow, only a few hundred feet above the gauge of the upper zone, utilizing a single electric cable to power up and communicate with the surface panels. All hydraulic valves were successfully tested and fully cycled in place and the packers installed at the programmed depths upon installation. The technology enhancement that supported five zones completions ranges from material technology, which permitted enough metal to be removed from the packers, where seven, quarter-inch bores, have to be drilled for control lines to be run to accommodate electronics and telecommunications. This development enabled up to 16 sensors to be connected by one single electrical conduit. The paper presents the production string concept, the technology used to achieve seven bores in the packer, while maintaining the packer's integrity, the complete sequence of pre-job preparation, and the installation outcomes, with its impact on the downhole flow controls.
Capillary Based Surface Controlled Subsurface Safety Valve Systems Solution for Problematic Wells
Authors: Wagner Alan N.
Published: February 2017

With growing regulatory requirements focusing on well safety and risk mitigating barriers, there is an increased requirement for surface-controlled subsurface safety valves (SCSSVs). Most SCSSV's provide well protection by means of a normally closed flapper-type closure mechanism that prohibits deployment of capillary or through-tubing based solutions which would not allow the flapper to fully close in the event of an ESD.

Operators desire cost effective rig-less deployment of capillary-based solution(s) to increase production and or reconnect a non-functional hydraulic control system. To date flow actuated subsurface controlled safety valves have provided a solution for loss of hydraulic control of a tubing-mounted SCSS; however, these valves are becoming less desired due to decreasing acceptance from regulatory agencies. Additionally, traditional post-completion chemical injection systems beyond a SCSSV have not been possible for continuous well-stimulant injection, nor has a solution for post-completion gage monitoring past a SCSSV been achieved.

This paper discusses technology enabling rig-less ability to reconnect a hydraulic system to a SCSSV or Safety Valve Landing Nipple by deploying a thru-tubing capillary based system inside the SCSSV / SVLN while maintaining functionality of the safety valve. In addition this solution can be utilized for continual injection of chemicals directly below the SCSSV and onwards to production zone depths. Further a downhole gage can be installed directly below the SCSSV and up to depths of 20,000 feet. Each of these functional characteristics can only be realized though the introduction of this novel capillary based solution, which maintains the "fail-safe" closure capability ensuring well control against a catastrophic event were to occurring at the surface or below.
Optimization of Underbalanced Coiled Tubing Drilling in Hard Sandstones
Authors: Al-Humood Malik Mohammad , Al-Khamees Shaker A , Mehmood Khalid , Cain Pat
Published: February 2017

Scope & Objective

Underbalanced coiled tubing drilling (UBCTD) is one of the keys to unlock the true potential of the tight and abrasive sandstone.

The sandstone formation is mainly characterized by hard and abrasive sandstones interbedded with shale and siltstone. Typically, the sandstone formations are encountered at very deep depths. They are the most difficult sandstone formations to drill, with rock unconfined compressive strength (UCS) of up to 35,000 psi and internal friction angles ranging from 25 to 60 degrees. These conditions make it very difficult to drill and reach optimal lateral lengths. Additionally, it is very difficult to perform an openhole sidetrack (OHST) in such hard and abrasive formations, compared to more porous carbonates.

Methods Procedures & Process

This paper will cover some of the key steps in optimizing underbalanced coiled tubing drilling in hard sandstones from different aspects such as drilling challenging profiles at high build rates, optimizing the rate of penetration (ROP), and also increasing formation contact by successfully performing OHST to deliver multiple laterals. The paper covers the following topics:

Results, Observations, Conclusions

The combination of technology and process has so far resulted in successful delivery of many sandstone wells with multiple laterals drilled on most of the wells, totalling more than 35000 ft in this hard and abrasive formation. The first-time success rate of openhole sidetracks was 96%. The average ROP and bit run lengths have also improved consistently.

Novel/Additive Information

It is expected that the recent improvements and consistency in delivering the sandstone UBCTD wells, will enable engineers to expand the horizon of UBCTD to several other fields, and tap the true potential of sandstone formations.
Fluidic Diode Autonomous ICD Multiphase Performance in Light-Oil Reservoirs
Authors: Corona Georgina , Fripp Michael , Yin Weiqi
Published: February 2017

Light-oil reservoirs are affected by the undesired production of water and gas. After breakthrough, these undesired fluids decrease the life of the well, leaving valuable reserves downhole. Inflow control devices (ICDs) delay the production of these undesired fluids; however, they become ineffective after water and gas production begins. Multiphase data and production installation history show how the Autonomous ICD (AICD) with fluidic dynamic technology favors the production of light oil while restricting gas and water.

The fluidic diode AICD completions have been successfully installed since 2011 in carbonate, sandstone reservoirs, as well as standalone screens and gravel pack completions. The fluidic diode AICD responds to changing well conditions with no action from the operator. When water and/or gas reach the wellbore, the AICD changes (with no moving parts) the flow path of the fluid and restricts its production. The flow through the device has been validated with extensive testing for single-phase oil, water, and gas. To characterize its performance with the mixture of oil and undesired fluids, multiphase testing has been performed simulating various water cuts (WCs) and gas volume fractions (GVFs).

The AICD was characterized by measuring the pressure drop vs. the flow rate at various oil viscosities that represent the light-oil formations in the Middle East. The WC and GVF of the test fluids were altered by increasing the water and gas ratio. This ratio increase enables representative testing of downhole conditions for Middle East reservoirs. The flow performance tests show that the fluidic diode AICD enhances the production of light oil and restricts water and gas as the ratio in the mixture of the undesired fluid increases. When comparing the AICD to a traditional ICD, the AICD exhibits at least 40% more flow of oil than water and approximately 50% less production of gas. Reduced water and gas flow helps reduce operating costs and represents more revenue from the oil production as a result of extending the life of the well.

The fluidic diode AICD is a reliable solution to increase the ultimate recovery with no intervention or moving parts. It has been proven that it can promote hydrocarbon production and restrict the production of gas and/or water. The AICD flow performance is predictable in single and multiphase flow. The fluidic diode AICD has been successfully installed in light-oil reservoirs in the Middle East and the North Sea.
The Use of Rock Physics Models in Exploration Contexts
Authors: Debec P.
Published: February 2017

The use of seismic amplitudes is crucial to understand the reservoir properties and fluid content. Because the Exploration themes and targets are changing, a very well informed and conscious interpretation of amplitudes is compulsory: are they illustrating petrophysical properties, facies, pressures, fluid content? The need for Rock Physics Models is more pressing than ever.

A Rock Physics Model (RPM) is a set of equations, relating rock density, incompressibility and shearing moduli (K and MU resp.) to intrinsic parameters such as mineralogy, porosity, facies, texture, etc. and external parameters such as burial, fluid, pore pressure, stress history, etc. A Rock Physics Model, when available, can help in estimating the elastic parameters of "any" rock, in "any" (calibrated) condition… [elastic parameters]=RPMRPM ([petrophysics]; [pore pressure].

Any combination of elastic parameter can be calculated. Density, K and Mu moduli are the native ones, then Vp, Vs, impedances (acoustic, elastic, shear), Lamé coefficients, reflectivity (near, far at any angle) can be easilly inferred. With a given wavelet, Near and Far synthetic traces, as well as AVO responses will give a priceless guide to seismic interpretation.

This paper doesn't aim at describing what an RPM is or how it is built and calibrated; but at describing the different uses, mainly in Exploration contexts.

This paper will illustrate the different fields of application of Rock Physics Models in Exploration contexts: –the first domain in which Rock Physics Models are not typically expected is Pore Pressure Prediction–one of the typical use of Rock Physics Models is for Reservoir Characterization (petrophysical properties)–it will also help risking geological scenari, selecting the ones that are fully consistent with seismic images (fullstack, near or far substack, avo…), and optimizing the others–Rock Physics Models may as well help to challenge the presence of hydrocarbon, by comparing the expected effects to those potentially due to lithology, porosity, burial and pressure variations.

This approach definitely leads to a better risk assessment: all those steps must be part of any DHI evaluation workflow.
Increasing Oil and Gas Production by the Application of Black Oil Foamers
Authors: Chakraborty Soma , Lehrer Scott E.
Published: February 2017

Objectives/Scope

As petroleum wells age, reservoir pressures decrease, and the hydrostatic head of liquid in the production tubing increases. In gas field applications, aqueous surfactant-based foamers and condensate foamers have successfully unloaded well fluids and increased production. However, neither technology is effective for crude oil wells.

Methods, Procedures, Process

Laboratory research was conducted to develop a black oil foamer (BOF) that could meet numerous field application requirements. The foamer had to be effective for a wide variety of crude oils and suitable for batch applications and continuous application by umbilical, capillary, or gas lift. The foamer also had to be thermally stable in the wellbore, not negatively impact asset integrity, and be non-emulsifying. The resulting foam had to be sufficiently stable to unload liquid from the well and resolvable by common defoamers. This paper describes several successful field applications of the new BOF.

Results, Observations, Conclusions

The BOF was applied into a subsea Gulf of Mexico oil well. This well experienced slugging and flowed intermittently for only 2 weeks, followed by an extended 6-month shut-in. After the well had been shut in for 2-months, the BOF was applied via umbilical and successfully unloaded the flowline and riser. The production cycle increased from 2 to 8 weeks and annualized oil recovery from 100,000 to 550,000 barrels oil. The foamer did not negatively impact oil/water separation or overboard water quality.

Novel/Additive Information

The application of a BOF can provide several benefits to the oil producer. It can alleviate liquid loading in flowing oil wells, increase oil and gas production, reduce slugging and downtime of cycling wells, improve suboptimal gas lift performance, and restart wells temporarily shut in for maintenance or due to liquid loading.
Innovative Non-Conductive Mud Borehole Imaging Technology Improves Turbidite Reservoir Characterization; Offshore Nile Delta, Egypt
Authors: Emam M. , El Araby A. , Nassar M. , Felifel E.
Published: February 2017

The Eastern Mediterranean hosts some of the largest and most prolific gas reservoirs in the region. These reservoirs have been deposited as slope submarine channels and basin floor turbidite sand sheets. The quantity and quality of production is often controlled by the architectural elements encountered. Slumped and deformed facies could hinder production in submarine channels of the slope setting, which are limited in lateral extent. Although laterally continuous and parallel thinly bedded turbidite sheets of the basin floor offer great lateral extent, they often exhibit poor vertical connectivity and low apparent resistivity due to thinly bedded sand/shale sequences.

An exploratory well was drilled in the Offshore Nile Delta targeting slope and basin floor deposits. Although seismic attribute interpretation provided a general outline of the area, there remained the uncertainty of whether the depositional setting encountered by the penetrated succession belonged to slope channels or basin floor setting. The value added through borehole image integration provided information regarding some unanswered questions: 1) Are sidewall cores representative of surrounding lithology? 2) Do sedimentary features support a slope or basin floor model? 3) Are there natural fractures to enhance porosity? 4) What is the reason for low porosity in the sands? 5) Are there additional thin beds between channel elements?

To answer all these questions, detailed structural, sedimentological and sand count analyses were performed on the micro-resistivity image, logged over a 500 m succession. Interpreted electro-facies differentiated the internal architectural elements from structural events within the penetrated succession. Slumping and water escape structures supported a slope channel setting while dip patterns directly above channel fills were interpreted as levee complexes of nearby channels. Sand counting of the image resistivity arrays included all possible thin beds that could contribute to pay while excluding all deformed facies that would hinder production performance.
Design of a New and Viscosity Independent Autonomous Inflow Control System
Authors: Rinde Trygve , Killie Rune , Lager Totte , Solberg Tron , Bakli Mikkel , Grüner Vegar
Published: February 2017

Breakthroughs of water and/or gas in production wells may have direct consequences for the production rates and overall field recovery factors. Multiple technologies have recently been developed to autonomously control inflow from the reservoir. Common to all these technologies is that new limitations are introduced which may have a negative impact on the well. This paper presents the design process for the next generation inflow control system and introduces new requirements for such completions.

Traditional Passive Inflow Control Devices (ICD) are designed to act in a preventive manner by setting up a somewhat more even inflow profile along the reservoir section and thereby delay the breakthrough of gas or water. More recently, several new initiatives have been presented which will operate autonomously and try to choke back unwanted production. Common to all these technologies is that viscosity differences are used to identify the flowing fluid phases. Viscosity differences between the reservoir fluids are therefore mandatory for these to work.

In this work the design process has been given an operational focus and the following requirements for the next generation autonomous inflow control devices have been defined: easy to install as an integrated part of the downhole completionrobust in design and functionalitysecures complete clean-up of mud and completion fluidsindependent of fluid viscositynegligible pressure drop during normal productionallows back-flow of fluids

In this paper a new design is proposed for the next generation autonomous inflow control valve which is independent on differences in fluid viscosities. The proposed valve blocks, or restricts, production of unwanted water or gas, and re-opens for production if oil comes back. It can be designed to stop water/gas production at a predetermined WC/GOR. Furthermore, the valve ensures efficient clean-up along the full length of the reservoir section and is insensitive to exposure to mud, particles and filtercake. The valve will not restrict any future well operations and can be designed with a fail-safe option.

The new design of autonomous inflow control systems represents a great technological improvement which will ensure robust, economical and fail safe design as well as removal of typical operational envelopes necessary for traditional technologies.
New Phase Transformation Fluid Based Loss Circulation Material: Hi-Strength, Year Round Use to Cure Severe to Total Loss in Reservoir and Non Reservoir Sections
Authors: Yadav Prahlad , Sarmah Pranjal , Jadhav Prakash , Agrawal Gaurav , Kosander Balraj , Tawat Najeeb Al , Addagalla Ajay
Published: February 2017

Loss zones are present all over the Arabian Peninsula geology. A fluid loss event not only causes non-productive time but also significantly increases the overall operations cost. With this motivation, we developed a completely new solution that is recommended for partial to total losses situations and useable year round for all zones including the reservoir section. This paper presents the science behind this new phase transformation fluid technology.

The new loss circulation material (LCM) was designed to be pumped easily, achieve thixotropic behavior under down-hole conditions resisting LCM from losing in thief zone prior to getting it set as a rigid plug with high compressive strength. This fluid phase transforming behavior is a result of pseudo-crosslink chemistry which differentiate this system from other commonly available solutions which are resin based or uses fibers or other network creating additives. Selective use of chemistry and additives used in the formulations changes the phase of fluid from easily flowable (allow pumpability using normally available surface equipment) to a thixotropic gel (to aid particulate carrying), from a low viscosity (enable formation entry) to a final hi-strength set material.

Thixotropy could be customized by varying the salt concentration. Salt tolerance gives the formulation compatibility with sea water. Thus LCM could be formulated with fresh water or the sea water. Fluid which is easily pumpable phase transforms to thixotropic fluid which helps carry the particulate content to the target zones. Customized setting control additive concentration ensures that LCM does not prematurely setup. Finally a high compressive strength solid plug is formed which can withstand the losses of fluids to the formation. High strength above 500 psi was measured.

This LCM is a fit for purpose technology with over 90% acid solubility which favors its use in reservoir section to minimize formation damage. If needed, LCM could be cleaned up using post-job acid flush.
Risk Based Statistical Approach to Predict Casing Leaks
Authors: Al-Ajmi Mohammed D. , Al-Shehri Dhafer , Al-Hajri Nasser M. , Mishkes Abdullrahman T , Al-Hajri Muhammad A. , Al-Shammari Nayef S.
Published: February 2017

This paper will present a statistical risk based approach to proactively predict casing leaks using Electromagnetic (EM) corrosion logs. The corrosion growth of downhole casing hotspots (areas likely to develop casing damage) is monitored to develop expectancy calculations of a typical well's remaining life.

Currently the predominant technology used for casing integrity measurement and monitoring are the EM corrosion logging tools. While this technology has provided a step-change in the ability to measure and monitor corrosion, the findings are not usually conclusive and need to be integrated with other data to make qualitative assessment. This is largely due to the nature of the tool's output where averaging is used to assess metal loss rather than direct measurement of the spot where metal loss is taking place. In other words, 50% average metal loss could mean a failure if one part of the casing is completely gone and the other is intact; or 50% metal loss is distributed evenly across the 360 degree circumference of a casing with no leak. This wide range of possibilities and uncertainty has made it extremely challenging to both interpret and analyze EM corrosion logging data. Establishing consistent criteria to classify the corrosion severity and confidently decide on the need to workover the well or not is a challenge to all field operators worldwide.

A probabilistic approach was introduced to improve EM corrosion logs' data interpretation. More than five hundred data points were collected and statistically analyzed to build a probability of failure model as a function of EM average metal thickness loss. These models were used to delineate a dynamic safe window of the average metal loss value across multiple casings.
Synthetic Iron Sulfide Scale and Polymeric Scale Dissolvers
Authors: Hafiz Taher , Hoegerl Manuel , AlSuwaij Ahmed , Almathami Abdulaziz
Published: February 2017

Iron sulfide scale challenges are well known in sour oil and gas fields. This paper discusses the laboratory synthesis of iron sulfide scale in an anoxic environment at near-reservoir conditions to approximate downhole formation of iron sulfide scale to yield a standardized scale with a defined multi-mineralogical composition for dissolver tests, reproducing scales similar to those commonly found in Khuff sour wells. Synthetic scales were characterized by SEM, XRD, and particle size distrubtion analysis. Dissolver performance tests with three commercial dissolvers are presented.
Wellhead for Rigless Cable-Deployed ESP
Authors: Darmawan D. F. , Helvenston A. , Borak E. , Roth B. A.
Published: February 2017

Wellhead and Xmas tree are the components at the surface of an oil or gas well that provide the structural and pressure-containing interface for the drilling and production equipment. During completion of the well, sometimes Electric Submersible Pumps (ESP's) are used to lift the oil from the well. Conventional ESP is deployed by attaching the ESP in line with the tubing string while the power cable is run outside of the tubing and then terminated at the wellhead tubing hanger section. A new rigless cable-deployed ESP is developed to reduce operation cost and to improve time efficiency. This new rigless cable-deployed ESP requires the ESP cable to be run cased inside the coil tubing, through the Xmas tree, and horizontally terminated at the specially designed vertical completion wellhead system. This paper focuses on the challenges, results, and lessons learned from the first prototype test of the specially designed wellhead for rigless cable-deployed ESP (rigless ESP wellhead) inside 7– completion tubing.

The rigless ESP wellhead system provides hang off and vertical production flow capabilities for the rigless cable-deployed ESP. This wellhead also enables the ESP cable to be terminated below the production Xmas tree and to self-align for the horizontal surface termination for external cable interface, isolated from the production bore fluids. As the ESP is run through the Xmas tree, the self-alignment system is very crucial for the successful termination of the ESP cable. A bowl protector is also an important part of the system which protects the seal area of the wellhead while running the ESP cable through the small bore area of the wellhead.

Existing coil cable-deployed ESP's in the market requires a horizontal completion Xmas tree for the production fluid to flow below the surface cable termination. Therefore large platform space is needed to accommodate the Xmas tree. The new rigless ESP wellhead system allows vertical flow of production fluid through the flow-by holes inside the wellhead around the surface cable termination. This design allows the use of standard vertical Xmas tree and does not require large horizontal space. Therefore, this system can be installed on existing platform space for upgrading current installed ESP to rigless cable-deployed ESP.

Lessons learned from the first successful prototype test will be used to improve the system for future field deployments, as well as for the design of similar systems for smaller size tubing (4-1/2″). As part of the wider rigless cable-deployed ESP system, rigless ESP wellhead will reduce the time and cost for ESP deployment and workover.