bluuebunny/crossref_metadata_2025 huggingface dataset:
Chemical Water Shutoff Pilot in a Mature Offshore Carbonate field
Authors: Cottin Christophe , Al-Amrie Omar , Barrois Emmanuel , Templier Arnaud , Salehi Nazanine , Zaitoun Alain
Published: November 2017

Total has been operating oil and gas production from a series of heterogeneous carbonate reservoirs offshore Abu Dhabi since 1974. New technologies to increase oil recovery have been always tested and deployed on this field as tertiary gas injection since the 1990's or chemical EOR with a surfactant polymer pilot recently. On the same dynamic, we tested chemical water shut off treatment on two highly waterflooded wells with the injection of relative permeability modifiers (microgels).

This paper describes the full workflow followed for the pilot implementation and lessons learnt.

A particularity of this field is to produce in commingle oil from different thin reservoirs, with permeabilities ranging from to 0.5 to 50mD. Well production is combined through a single sliding sleeve, thus any mechanical shut off is impossible to block the water coming from the high permeability zones that is why the injection of RPM was considered.

Microgels were preferred over conventional polymers gels due to their higher resistance to salinity, shear, and H2S.

Laboratory studies were conducted to select the best microgel size and to obtain inputs for near well-bore model simulation (microgel adsorption, permeability reduction, injectivity). Numerical simulations were performed to predict the well responses and to define the optimal slug injection.

For this first pilot using microgels in high salinity environment, two vertical wells producing from two different reservoirs were tested, with watercut of 92 and 97%.

The microgel fluids were bullheaded into the whole perforated interval, the fluids were prepared on a nearby marine vessel; the operational challenges faced are detailed.

Preliminary results and way forward are described. The application of this microgel technology to high salinity and moderate temperature carbonate fields has a great potential to improve recovery in very mature fields at low cost.
Implementation of High Resolution Diagenetic Features into the Static and Dynamic Reservoir Models of a Giant Offshore Oil Field, Abu Dhabi
Authors: Shekhar Ravi , Naqbi Amna Al , Obeta Chukwudi , Ottinger Gary , Herrmann Rolf , Obara Tomohiro , Almazrouei Shamsa J. , Maqrami Zinab N. , Neyadi Abdulla Al , Edwards Ewart , Shebl Hesham , Li Dachang , Shehhi Budoor Hasan , Fazal Ayub
Published: November 2017

Lower Cretaceous-aged carbonate sediments in a supergiant Middle Eastern oil field are characterized by extensive diagenetic overprints (e.g., dolomitized burrows, dissolution fabrics and fractures) which occur over areas of several kilometers. Due to the permeability contrast with respect to surrounding fine-grained matrix, the diagenetic features are believed to play an important role in reservoir fluid-flow, particularly as a major contributor to early water breakthrough observed in the field. Uncertainties associated with three-dimensional subsurface reservoir models can be mitigated by incorporating the results of detailed reservoir characterization studies. How these study findings are successfully and meaningfully implemented into the reservoir model can be a challenge and requires an integrated effort by reservoir geologists, modelers, and engineers.

This paper discusses a comprehensive reservoir characterization and modeling study conducted to capture the impact of diagenetic features on reservoir flow properties. A novel method was developed to map the spatial and stratigraphic distribution of these features from cores. Dolomitized burrows generally appear in core as randomly oriented features on a scale of cm to 10's of cm. They are characterized by grainier fill (packstone or grainstone), often dolomitized, within a background of muddier sediment (wackestone to packstone). Dissolution vugs are associated with algal rock type and can vary from few cms to 10's of cm. Fractures are generally layer specific and occur at the reservoir-dense boundaries. The origin of diagenetic processes and prediction of their occurrence is very difficult. However, the difference in texture and associated pore characteristics lead to heterogeneous porosity and permeability regimes that can have significant impact on sweep efficiency and recovery in oil fields that are subjected to waterflood.

A simplified, fit-for-purpose, rapidly updateable static model has been developed to ensure accurate stratigraphic and lateral distribution of diagenetic features based on cores, logs and dynamic data. Whole core data revealed potential guidance for assigning permeability in diagenetic features. A consistent SCAL framework has been developed to capture the relative effects of these diagenetic features on flow. After incorporation in the model, simulation results clearly shows water movement through these features and rapid water cut. This is in agreement to the field observation that has experienced earlier than expected water breakthrough and steady increases in water cut over time.
High-Resolution Sequence Stratigraphy Analysis and Diagenesis Evolution of a Barremian Carbonate Platform Kharaib Formation, Onshore Abu Dhabi
Authors: Torres Kevin Michael , Ugonoh Mohammed Salawu , Al Hashmi Noor Faisal
Published: November 2017

The aim of this study is to propose a stratigraphic and sedimentary framework though the integration of available sedimentary, diagenetic and petrophysical data, which will be utilized in the construction of a high resolution stratigraphic framework, as an input into comprehensive review and update of an existing model of heterogeneous carbonate reservoir in a mature field in Abu Dhabi, UAE.

Depositional facies have been defined in cored wells, subsequently were associated taking into account the biologic and sedimentary processes in response of carbonate growing and sea level changes, allowing the identification of the main stratigraphic surfaces.

Surfaces can extend the correlation along the field and define the model of facies that, with the evidence provided by cores, can recreate and predict the different regressive-transgressive cycles in high resolution which the carbonate platform were undergone during its evolution.

Diagenetic evolution, interpreted through laboratory observations, was integrated with facies and petrophysical evaluation allowing the understanding of the spatial distribution of petrophysical properties within a heterogeneous reservoir and define a new set of facies which will be used in the generation of geological static model.

Application of sequence stratigraphy methods in cores, and extended in logs allowed the identification of six depositional sequences, with thicknesses of 2 to 4 meters each, corresponding to the phases of carbonate platform growth. Within each depositional sequences, typical cycles were defined that support the understanding in the association of facies and their relationship during the deposition.

The identification of sedimentological cycles not only genetically organizes the facies and predicts the stacking pattern, but also makes possible to find an excellent correspondence between cycles from lowstand system track intervals with good to excellent permeability values, and cycles from transgressive system track intervals with low permeabilities.

Many of the sequence stratigraphy published articles driven for the most important reservoirs along the Arabian Plate, provide an excellent tool in the regional correlation. However, they are not enough to be used in the reservoir characterization in detail that is required during the development of the field neither as input data in the generation of geological static models that use the sedimentary trends as constrain to populate the petrophysical properties.
Maximizing Production Performance in an Undeveloped Reservoir: A Case Study, Offshore Abu Dhabi
Authors: Al-Hassani Sultan Dahi , AL-Tameemi Ibrahim Mohamed , Khan Owais Ameer , Ahmed Shafiq Naseem , Keshta Osama , Chaudhry Mohamed Zubair , Fares Wael , Essam Ramy , Abdulkarim Anar , Aki Ahmet
Published: November 2017

The value of the continuing integration of logging-while-drilling (LWD) and directional drilling processes has been more prominent in the current economic environment in terms of optimizing field development costs by means of precise well placement, as well as improved reservoir characterization and drilling performance in real time. A successful horizontal drain was drilled in an undeveloped Reservoir A for the first time in an offshore carbonate sequence, using advanced LWD acoustic and high-resolution microresistivity sensors.

The well plan required maximizing the exposure of the most porous body in a thinner sublayer. This sublayer lies directly over a large, developed carbonate reservoir as part of the Upper Jurassic Carbonate sequence located offshore Abu Dhabi.

The flow test results during the drillstem test (DST) operation for the first appraisal well in the target reservoir produced at a rate that was greater than expected. Production log data were acquired and integrated with the LWD microresistivity image interpretation. In addition, in this environment, the inferred Rt and Rxo measurements from the LWD azimuthal focused resistivity tool were shown to be more reliable than conventional electromagnetic wave resistivity measurements, which are prone to exhibiting significant polarization, anisotropy, and bed boundary effects.

Lessons learned from the first appraisal well in Reservoir A for reservoir characterization and flow unit identification were used and implemented in the planning and successful delivery of the future horizontal wells.

Unlike the other reservoir subunits that are deposited within the same sequence, the field development strategy for these undeveloped reservoirs has been under review based on the recent data. The field development strategy used enhancements in well placement, formation evaluation, and production technologies, including extended reach horizontal wells, with maximized reservoir exposure in the sweetest zones, to compensate for the poor petrophysical character and low oil mobility.

This case study presents insights into the advanced geosteering and multidisciplinary reservoir characterization processes along these successful horizontal drains drilled in undeveloped Reservoir A

and the future horizontal wells. It also demonstrates the integration between the geological and petrophysical interpretation and the use of acoustic measurements and high-resolution microresistivity imaging. This combination has enhanced the understanding of Reservoir A in terms of the unexpected production performance and helped optimize efforts for the future field development plan.
Novel Method for Consistent Initialization of Reservoir Simulation Models with Oil/Water Paleo-Contacts
Authors: Patacchini Leonardo , Mohmed Farzeen , Lavenu Arthur P. , Ouzzane Djamel , Hinkley Richard , Crockett Steven , Bedewi Mahmoud
Published: November 2017

The classic method for initializing reservoir simulation models in the presence of a transition zone, based on primary drainage capillary-gravity equilibrium, is extended to account for partial reimbibition post oil migration. This tackles situations where structural events, such as trap tilting or caprock leakage, caused the current free-water level (FWL) to rise above deeper paleo-contacts.

A preliminary primary drainage initialization is performed with zero capillary pressure at the paleo (or deepest historical) FWL, to obtain a minimum historical water saturation distribution. From a capillary pressure hysteresis model, it is then possible to determine the appropriate imbibition scanning curve for each gridblock, which are used to perform a second initialization with zero capillary pressure at the current FWL.

With the proposed method, log-derived saturation profiles can be honored using a physically meaningful capillary pressure model. Furthermore, when relative permeability hysteresis is active, it is possible as a byproduct of the initialization to assign the correct scanning curves at time zero to each gridblock, which ensures that initial phase mobilities (hence reservoir productivity) and residual oil saturation (hence recoverable oil to waterflood) are modeled correctly. This is demonstrated with a synthetic vertical 1D model.

The method was implemented in a commercial reservoir simulator to support modeling work for a giant undeveloped carbonate reservoir, where available data suggest that more than 3/4 of the initial oil in place could be located between the current FWL and a dome-shaped paleo-FWL. This work is used as a case study to illustrate the elegance of the proposed method in the presence of multiple (or tilted) paleo-FWLs, as only one set of capillary pressure curves per dynamic rock-type is required to honor the complex log-derived saturation distribution.
Porosity Measurements on Drill Cuttings - Comprehensive Inputs to Formation Evaluation near Real-Time While Drilling
Authors: Kesserwan Hasan , Alshanqaiti Elham , Jin Guodong , Nuic Ivo
Published: November 2017

The use of drill cuttings in the reservoir characterization can help to understand the reservoir properties. This is promoted by the need of near-real time formation parameters to calibrate the logs acquired while drilling and/or in horizontal wells where conventional coring is not an option. Similar to the cores, the measurements performed on cuttings are always challenged against both experiments and interpretation procedures, however with larger margins of uncertainties. We focus this study on measuring the cutting porosity and pore size distributions to highlight the impacts of cutting size on the reliability of the results to represent the actual formation porosityespecially for complex rocks.

We determined the porosity using the solid and the pore volumes of drill cuttings obtained from sandstone and carbonate rocks. After cleaning and drying, the solid volume is measured using a gas pycnometer. The pore volume is then measured using NMR T2 relaxation in saturated surface dry drill cuttings (SSD). The porosity and pore size distributionsmeasured on sandstones and carbonates cuttings (down to 1 mm) matched very well the core measured values. The complexity of the rock, though, is found deterministic for reliability of the cuttings especially for the carbonates at reduced cutting sizes. We also emphasized on the effects of the water-film that forms on the surface of the cuttings on porosity readings.
QRA Ruleset for the Sour Pipelines of the Kashagan Field
Authors: Scaperdas Athena , Lines Ian , Young Marc , Pennicott Philip
Published: November 2017

Many but not all Oil & Gas operators develop company rulesets for Quantitative Risk Assessments (QRAs). For those that do, it is to ensure a consistent and high standard approach across all company assets, aiming to achieve a balance between modelling simplification and complexity. A QRA ruleset has been developed for the Kashagan field in Kazakhstan by the North Caspian Operating Company NV (NCOC), with the purpose of addressing the specific challenges associated with quantifying the risk of toxic releases from high-pressure, high-H2S content pipelines. This paper summarises the analytical approach given in the ruleset, and explains how it was developed, by bringing together the most up-to-date guidance available in the industry.

The main themes presented in this paper are: methodologies used to assess H2S risks to the general public, including the effect of concentration fluctuations and the choice of averaging time; the choice of dispersion model for far-field dispersion; and defining appropriate 'source terms’ for the dispersion modelling in order to account for the effect of ground cover on buried pipelines and to allow the full-bore ‘crater’ releases to be characterised more realistically. Calculating the probability of releases, especially those for the largest full-bore releases, is another important consideration.
Digital Slickline: One Stop Shop for Well Intervention
Authors: Jongnarungsin Sarunya , Jafar Feras Abu , Ali Abdulla Bu , Laoroongroj Ajana , Hariry Ahmed El , Puttisounthorn Toon
Published: November 2017

The current low oil price environment has driven a renewed focus on managing costs while minimizing exposure to operational risk, and lightweight well intervention activities have not been exempt from this scrutiny.

Electric line (E-line) and conventional slickline are important and frequently used tools for light well intervention operations, and are often used at different times during the same well intervention program, leading to multiple rig-ups and rig-downs of the equipment, as well as the requirement to transport both units to the platform. This paper presents a case study of the use of digital slickline technology to perform typical slickline and typical electric line operations with the same digital slickline unit, thus saving costs and reducing risk by eliminating some rig up/rig down activities, minimizing equipment handling, and downscaling crew size.

Mubadala Petroleum performs rig less activities similar to other oil operators in the region. Both slickline and electric line equipment must be mobilized to the platform and rigged up separately. This creates inefficiency with logistics, operations, while increasing risk and results in higher overall operational costs. With the introduction of digital slickline to offshore operations, it has changed the way that Mubadala Petroleum performs rig less intervention.

The digital slickline data plots shown in this paper are representative real examples of its application. Interventions executed using real time digital slickline have proven to be safer, improve efficiency and are a more cost-effective way to conduct operations by having full real-time control of downhole tool and sensors. It also reduces total foot print of equipment and personnel during simultaneous slickline and electric line operation by utilizing a single digital slickline unit to cover both downhole mechanicals, perforation and real-time logging work scope without switching back and forth between units. Depth accuracy and shot detection was achieved with lower operational risk while working with perforation guns and explosives.

Material presented in the paper are from actual operations, with examples of perforation, depth correlation, pressure surveys, and pressure monitoring while perforating, and demonstrate the operational efficiencies and risk reduction being delivered.
Investigating Low Resistivity-Low Contrast Resistivity Pay in a Permo-Carboniferous Reservoir, Central Saudi Arabia
Authors: Ayadiuno C. B. , Khan S. , AlAbbad A. A. , AlMohsen F.
Published: November 2017

The Permo-Carboniferous reservoirs of central Saudi Arabia comprise important accumulations of natural gas and light oils. Some of the reservoirs exhibit low resistivity and low contrast resistivity (LRLC) phenomena. Low resistivity pay reservoirs often produce gas/oil with little or no water at very low resistivities. Low contrast resistivity pay zones, on the other hand, produce hydrocarbon at minimum resistivity contrast between hydrocarbon-bearing intervals and adjacent water-wet or shaley zones. Evaluating these types of reservoirs poses a major challenge to petrophysicists and petroleum engineers due to the difficulty in recognizing them on logs and quantifying their hydrocarbon potential when using simple resistivity-based petrophysical models. As a result, potential pay zones can be incorrectly evaluated or bypassed. The objectives of this study, therefore, are: 1) to understand the causes of LRLC pay in the study reservoirs through a detailed assessment of the textural and mineralogical composition of the rock, and 2) to validate a simple porosity-based methodology for recognizing LRLC pay in both old and new wells.

To achieve the set objectives, 38 core samples and 107 thin sections were selected from two wells exhibiting low resistivity (Well-1) and low contrast resistivity (Well-2) phenomena, for detailed petrographic and mineralogical studies (SEM/XRD). Furthermore, a water salinity map was created to provide general salinity trends in the area. Well data combined with results of mineralogical and petrographic studies suggest that low resistivity and low contrast resistivity pay in the study reservoirs is the product of a complex mix of: 1) clay mineral types and its mode of distribution, 2) thin reservoirs below resistivity tool resolution, 3) significant grain size variation and microporosity, and 4) variable formation water salinities.

This paper highlights the causes of low resistivity and low contrast resistivity phenomena in reservoirs in central Saudi Arabia. Furthermore, the applicability of a porosity-based methodology for recognizing LRLC phenomena was verified with promising results.
Low Pressure Operation LPO: Extending Field Life of Several High H2S Fields with Minimum Costs
Authors: Hadhrami A. , Mihajlov R. , Muthalaly M. , Schulz R. , Alias Z. , Riyami A. , Abri Z.
Published: November 2017

Several high pressure (up to 1000 bar), deep (3-5 km) and high sour oil (H2S/CO2 up to 10%/25%) fields have been in primary depletion production in the Southern Sour Cluster in Petroleum Development Oman (PDO) for the last several years. These fields are currently nearing lift-die out or have already experienced lift die out. These carbonate (and silycillite) fields form stringers which are encapsulated by salt and thus lack natural aquifer support. The only drive mechanism has been up to now fluid (and rock) expansion. Artificial lift in form of high cost Electrical Submersible Pumps (ESPs) was attempted in 3 wells and failed due to suspected design and installation issues, including depth of the reservoir. To extend the depletion production life a Low Pressure Operation (LPO) has been proposed across all the 3 stations within the cluster and all currently being executed. LPO makes smart and sustainable use of existing facilities by simply re-routing incoming trunk line in three stations to the low pressure separator. Several other options were screened but were found to be less attractive. LPO will allow continuation of depletion production for several years until Miscible Gas Injection (MGI) is implemented as a next development phase. LPO concept is commercially extremely attractive with very low Unit Technical Costs (UTCs) of less than $10/bbls and high Value Investment Ratio (VIR) of more than 20.
Impact of Irreversible Retention on Tracer Deployments; Constraining Novel Material Deployments
Authors: Chen Hsieh , Kmetz Anthony A. , Cox Jason R. , Poitzsch Martin E.
Published: November 2017

Full field inter well tracer programs have become more and more ubiquitous for effective reservoir surveillance. Novel tracer materials with much higher detectability and lower costs have been actively screened. One of the biggest challenges in deploying novel material types, however, is their elevated irreversible retention to reservoir rocks. Herein we benchmarked traditional inter well tracer chemicals and then the sensitivity of ever-increasing irreversible retention that might be associated with unconventional materials.

Using field-scale reservoir simulations with a Langmuir-type tracer irreversible retention model, we rigorously test the limits for tracer irreversible retention in order to have successful inter well tracer test (IWTT). Specifically, we studied the tracer breakthrough peak concentrations as a function of tracer irreversible retention as well as inter well spacing in synthetic waterflood patterns. Custom reservoir simulator functionalities were built to perform the simulations. Additionally, coreflood experiments on common oil field tracers were conducted to acquire independent irreversible retention values and compared to the modeling results.

For the reservoir simulations, we first tested the ideal tracer case with no irreversible retention and found perfect agreement with the standard Brigham-Smith model. We then tested for tracer breakthroughs with increasing irreversible retention values and found that the tracer breakthrough peak concentration drops off dramatically. With the consideration that the limit of detection (LOD) of contemporary analytical instruments are at the part per trillion (ppt) level, the simulation results suggested that the tracer irreversible retention should be less than 10 μg/g-rock (mass of adsorbed tracer / mass of rock) in order to have meaningful IWTT with a well spacing of 2000 ft and an injection tracer mass up to 100 kg. Finally, two field tests using fluorobenzoic acid (FBA) based tracers deployed in the highly saline and retentive carbonate reservoirs in Saudi Arabia were compared. The irreversible retention number of the FBA based tracers was estimated to be less than 5 μg/g-rock from the model. Corresponding coreflood experiments for FBA tracers in high temperature and salinity carbonate cores show 0 +/− 10 μg/g-rock irreversible retention number within error ranges, verifying the prediction of our simulation results.

This paper broadens the scope of the extensively used Brigham-Smith tracer behavior model by incorporating tracer irreversible retention effects. More accurate design and interpretation of inter well tracer tests may be achieved through the new insights presented. Better waterflood management can then be established because of the reduced uncertainties from the more precise tracer data. In addition, this study set an unambiguous standard for the tolerable irreversible retention limits for any new materials targeting inter well tracing applications.
Advanced Fracture Modeling: Lab Experiments to Field Applications
Authors: Gosavi Shekhar V. , Kumar Sandeep , Kirane Kedar , Garzon Jorge , Sanz Pablo , Biediger Erika , Searles Kevin , Nygaard Kris
Published: November 2017

This article describes the development, validation, and application of a fully coupled Finite Element (FE) framework for modeling of hydraulic fractures in the context of a diverse set of oil & gas (O&G) problems. The models have been developed within a fully-implicit non-linear FE solver, and comprise two widely established fracture modeling methods: Cohesive Zone Method or CZM (mesh conforms to a pre-defined fracture path) and eXtended Finite Element Method or XFEM (fracture geometry evolves independent of the finite element mesh).

The models were verified by comparing simulation results with analytical solutions for the four asymptotic regimes of fracture propagation. The models were also experimentally validated, which involved comparing simulations with carefully conducted polyaxial fracturing experiments. For this purpose, a comprehensive set of laboratory-scale polyaxial fracturing experiments were conducted. Then, the finite element models were used to simulate these experiments, and the simulation results were compared with the experimental results.

The applicability of these models spans conventional as well unconventional fracturing problems, including 3D multi-zone injection, diagnostic fracture injection tests, and multi-stage hydraulic fracturing. To demonstrate this, a number of field-scale models are constructed and applied to a broad range of O&G problems involving fracture propagation at large length and time scales. These include a Step Rate Test (SRT), a Produced Water Re-injection (PWRI) problem, and a Cuttings Re-Injection (CRI) simulation. These large length- and time-scale simulations were enabled by a high-performance, massively parallel computing system.

Through the various validation exercises and the field examples discussed in this work, we intend to demonstrate the applicability of the newly developed fracture modeling capabilities in successfully simulating real problems ranging from laboratory-scale to field-scale.
Sampling From the Posterior in Reservoir Simulation
Authors: Ramirez B. A. , Gelderblom P. P. , Eales A. D. , Chen X. , Hobson M. P. , Esler K.
Published: November 2017

In recent years, there has been significant effort within reservoir engineering to move towards reservoir simulation studies that rigorously accounts for uncertainties in the model parameters when developing production forecasts. Probabilistic history matching approaches play an increasingly integral role in the calibration of subsurface reservoir models to dynamic data. In a Bayesian fashion, the calibration process employs prior distributions for the uncertain parameters and the likelihood function to generate posterior distributions.

Due to the impossibility of having a closed form for the reservoir simulation evaluations, uncertainty quantification is done via sampling methodologies. Markov Chain Monte Carlo (MCMC) is the widely-accepted uncertainty quantification technique used for this purpose. MCMC applications often require several millions of evaluations of a forward model. In reservoir engineering, each forward evaluation (reservoir simulation) can take hours, direct application of MCMC is too computationally expensive in most real-world applications.

In reservoir simulation applications, sampling is usually performed indirectly via proxies, which replace each forward evaluation with an inexpensive one. The accuracy of the results relies strongly on the ability of the proxy to robustly represent the high-dimensional relationship between the model parameters and the simulator output. The industry standard, polynomial response surface regression, can be quite inaccurate when assessed using blind testing. In addition, the number of simulation runs required to construct an adequate proxy model can itself be prohibitively large.

We present a novel application of Bayesian inference within the reservoir simulation domain. A parallelized nested sampling workflow is integrated with ultra-fast reservoir simulation technology running on Graphics Processing Units (GPUs). MultiNest, a variant of nested sampling, has been shown to require fewer number of runs than conventional MCMC algorithms such as Metropolis-Hasting. In large models, GPUs significantly accelerate each forward evaluation compared to models running solely on Central Processing Units (CPUs). The combination of nested sampling and accelerated simulations results in a rigorous methodology that can be used to quantify uncertainty in reservoir simulation workflows.

The methodology has been applied to synthetic models and field models. It is affordable in terms of cost and elapsed time. Examples are shown to illustrate the capabilities of the workflow.
Comprehensive Role of Structural Integrity Management for Offshore Assets – Project Case
Authors: ELHabbal Mohamed
Published: November 2017

Structural Integrity management (SIM) system is considered one of the main pillars of Asset Integrity Management (AIM) as SIM system role is to ensure and maintain asset structural integrity and fitness for purpose allowing assets owners to flexibly accomplish their business objectives and achieve sustainable operation of their assets. For Offshore and subsea Assets; the importance of SIM gets even more due to the high costs of Inspection, Maintenance and Repair (IMR) activities.

The objective of this paper is to introduce to the Oil & Gas stake holders in the offshore market a deep understanding of SIM methodology and the procedures of establishing SIM system for their assets according to the API RP 2SIM practices which is considered one of the state-of-art practices to manage fixed offshore platforms integrity.

The paper objective is achieved by representing a true project case applying practices and procedures of API RP 2SIM for a 120 Platform fleet using Qualitative (Risk Based) approach describing the basis of platforms data gathering, categorization, ranking and selection for assessment, setting inspection strategy & planning.

It is concluded from this paper that SIM system is an enabler of the success of AIM system, and qualitative approach is considered a reliable and economic method for dealing with SIM projects, wall thickness measurements has a key role in the integrity of offshore platforms, software has a key role in SIM system sustainability and finally acceptance criteria is one of key issues that needs to be addressed in SIM projects. Added to that a set of recommendations is proposed to API RP 2SIM that might be useful to be considered next version.

This paper shares with our stake holders in the oil & gas market a valuable experience of constructing a SIM system for operators using a real life project case, introduce comprehensive application of recommended practices and finally deepen the awareness of importance of SIM systems for sustainable development of offshore oil & gas assets.
Optimization Of Green Field Development Using Multi-Realization Approach
Authors: Semenov Andrey
Published: November 2017

One of the widely known use cases of 3D simulation model is the field development optimization. This task usually requires multiple numerical experiments (simulation runs) under different scenario conditions. Analysis of the huge space of input parameters and multiple runs is time consuming. Also, there is a lack of logic in such process driven by common management requests "run the case". In the scope of the paper, the system approach for analysis of broad parameters space is presented combined with robust techniques for analysis of multiple numerical experiments. The method is demonstrated on the example of solving 2 tasks: determination of the optimal gas usage distribution and selection of the best water injection strategy.

2 separated 3D reservoir simulation models were used in the study. Models have been constructed in commercially available reservoir simulator and another tool was used to substitute variable model parameters by modifiers. Gas injection rates, maximum reservoir production rate, water injection rates, positions of water injection wells, and target reservoir pressure were investigated to find the optimal (in terms of cumulative oil production) reservoir development strategy. On the final step, optimal reservoir development strategy was utilized in the integrated reservoir simulation model.

Based on the analysis of multiple runs with different combinations of reservoir management parameters, the optimal development strategy was formulated for 5 reservoirs. Implementation of optimal positions of water injectors is adding 2% to recovery factor. Usage of proper injection gas allocation strategy is allowing keeping average reservoir pressure above minimum miscibility pressure during the whole reservoir development time and substantially increases cumulative oil production. Summarizing, implementation of the optimal reservoir development strategy (maximum reservoir production rates, gas and water injection rates, and injection wells position) is absolutely crucial for success of reservoir development. Advanced optimization approach using multiple realizations of input parameters was used. More than 100 runs have been simulated and analyzed with prior and posterior distributions of parameters.
Experimental Investigation of Cuttings Transport in Horizontal Wells Using Aerated Drilling Fluids
Authors: Gul Sercan , Kuru Ergun , Parlaktuna Mahmut
Published: November 2017

An experimental study has been conducted to investigate the cuttings transport in horizontal wellbores using aerated drilling fluids. An advanced flow loop system with 21 ft. long annular test section composed of 2.91-in. ID transparent casing and 1.85 in. OD inner drill pipe has been used for the experiments.

Aerated fluids were composed of air/water and air/drag reducing polymer fluid mixtures. Partially hydrolyzed polyacrylamide (PHPA) copolymer was used as a drag reducing agent. Drag reducing polymer fluids (i.e. water-polymer mixtures)were prepared usingPHPA concentrations of0.05% V/V, 0.07%V/V, and 0.10% V/V. The optimum PHPA concentrationwas found to be 0.07%V/Vresulting maximum drag reduction of 41.88%.

Four different flow regimes were identified along with the flow of aerated fluids as bubble, elongated bubble, slug and wavy annular regimes. Adding PHPA polymers in water delayedthe transition from slug to annular wavy flow regime (i.e. for a given liquid flow rate the transition from slug to wavy annular flow regime was observed at higher gas flow rates).

The annular area occupied by the cuttings decreased with the increasing liquid(both water and polymer fluid) and gas flow rates. However, increasing the liquid flow rate was more effective in terms reducing the cuttings bed deposition.

On average, the use of 0.07% PHPA polymer fluid with air for cuttings transport caused 23.90% drag reduction while reducing the annular area occupied by the cuttings by 4% and cuttings bed height by 13.78%.

Though cuttings transport performance of the various flow regimes did not show significant difference, Wavy Annular flow regime seemed to be the most effective flow regime in terms of cuttings transport among the others.
Recent Exploration Activities in Eastern Onshore Abu Dhabi: Implications of the First Exploration Well in 30 Years in the Region
Authors: Fava L. , Rock G. , Conradi F. , Aliabadi R. , Kwiecinski E. , Shateri A. Al , Witte J. M. , Hijleh Y. I.
Published: November 2017

OMV and ADNOC signed a study agreement in 2013 to explore for hydrocarbons in a large (10,000km2) under-explored onshore area, named East Abu Dhabi. The objective of the work programme was to evaluate the conventional and unconventional hydrocarbon potential within multiple play types and structural settings, via the analysis of existing vintage data, acquisition of new seismic followed by exploration drilling.

To date 1,800km2 3D (4S) and 700km 2D seismic have been acquired focused on two principal play types; namely, the ‘Pabdeh’ stratigraphic play and the ‘Thamama’ combined structural/stratigraphic play. Additional studies completed include fluid inclusion stratigraphy using data from nearby vintage wells, and the completion of an unconventional study covering the wider area of interest. The first OMV operated exploration well reached its TD in the Jurassic in March 2017. Two tests have been performed in Lower Cretaceous and Jurassic resulting in a dry sour gas discovery.

The main results of the well that have an impact on the understanding of the regional geology can be summarized as follows: 1) Source Rock, three potential source rock intervals have been penetrated (Middle and Lower Cretaceous & Jurassic). 2) Reservoir, The middle Cretaceous has been found in a back-shoal facies with its suggested corresponding platform margin being located in close proximity to the South-West. The Aptian is represented by the classical Lower Shuaiba fm. and overlain by the Bab shales. No isolated platform has been encountered. 3) Clear stratigraphic and structural evidence supporting structural deformation of the Thamama Group during the Lower Cretaceous. Several distinct fault trends are evidenced from both the well data and 3D seismic depth slices. Understanding these faults and related fracture systems will be fundamental in understanding the play potential in the wider area.

This is the first exploration well to be drilled in the area since the ‘80s. Multiple intervals of regional interest have been encountered spanning the massive loss circulation intervals of the Palaeocene, conventional and unconventional reservoir within the Middle Cretaceous, the entire Lower Cretaceous sequence and the Asab equivalents of the Upper Jurassic.
Alert Today, Alive Tomorrow! Embedding Process Safety Across Organization
Authors: Khan Shamsuddin Ahmad
Published: November 2017

What is difference between Process Safety & Personal Safety?

How can you contribute in making your work place safe?

How your routine activity can prevent Process Safety Incident?

These are few of the questions commonly asked in industries now-a-days. During the past decade, industries have made tremendous efforts in developing robust and effective systems in Health, Safety & Environment, now it is call of the day to focus on Process Safety as well. Process safety differs from personnel safety and has to be dealt differently. Personnel safety deals with injuries that a worker can suffer while doing his job, such as burns, cuts, strains, and fume exposure, while process safety starts with failure of an equipment or system to perform its intended function, thus leading to catastrophic fires, explosions, and toxic releases. Process safety incidents have the potential to kill or injure many workers and even neighbors of the facility and can even lead to long term or permanent shut down of a processing facility.

Process safety leadership and culture are recognized as key factors for effective process safety management implementation. Everyone working in any industry should enhance awareness of his team & himself towards Process Safety and to initiate a drive towards developing Process Safety Culture within organizations whereby mitigation & elimination of potential hazards is embedded in the attitude of every individual.
Real-Time Operation: Game Changer Towards Effective and Collaborative Drilling Operation
Authors: Atemin Azizul , Iskandar Farah Farhana , Abd Aziz Amir
Published: November 2017

PETRONAS has adopted drilling operation digitalization and formed real-time drilling operation center; which is also known as WELLS RTC since a decade ago, in conjunction with the company’s recent theme – Collaboration, Pace and Going Digital. Traditionally, a real-time drilling operation center has always been perceived as a monitoring center only for quick decision making to reduce Non-Productive Time (NPT). However, over the years the centre has evolved and not only has proven how the real-time operation center has allowed real – time problem solving, but it has actually brings so much additional value to the company as a whole. It has been the centre of drilling process and workflow efficiency transformation, the knowledge transfer and the collaborative discussion between multiple disciplines team that involved in drilling planning and operation.

Prior to the existence of WELLS RTC, communications were made via emails and phone calls. Delayed decisions and miscommunication occurred along the way. WELLS RTC which operates 24/7 acts as collaboration center that provides avenue for the subject matter experts (SME) to discuss and make real time decision when needed. Collaboration & discussion is not confined to just Drilling Engineers, but includes and not limited to the Geological and Geophysical (G&G) team who are working on the well. Real-time data is now being stored in PETRONAS data center allowing the company to have full access to their own data.

A direct impact of having a real-time operation center is the improved communication between each personnel who are involve in the drilling operation. Tough decisions are now easier to be made especially when the SMEs are sitting together under one roof looking at the real-time data transmitted from the rig site.

Also, having full access to PETRONAS historical data allows the employee to search for the lesson learnt and best practices on the previous wells/fields allowing them to make more educated judgment (when needed) based on existing data. This data can be made available immediately for case study purposes. Software environments that are able to connect data between multiple servicing companies using the Wellsite Information Transfer Standard Mark Up Language (WITSML) format has resulted in increased accuracy of data communication which is needed for collaborative discussion.

This paper will describe and explain the benefits of having a real-time drilling operation center via case studies studies on collaboration between multiple work groups contribute to the success of multiple drilling projects delivery and the technology used to setup this center.
Formulation of Inhibitive Water Based Mud System with Synthesized Graft Copolymer: A Novel Approach to Mitigate the Wellbore Instability Problems in Shale Formation
Authors: Kumar Saket , Sundriyal Priyanka , Kumar Nitesh
Published: November 2017

This research paper discusses about the evaluation of carboxymethyl starch-grafted-polyacrylamidecoplymer as a potential drilling mud additive for the drilling of reactive shale formations. The graft copolymer was synthesized via carboxymethylation and free polymerization technique and it was characterized by FTIR, and SEM. Then, it was processed in the development of the WBDMS. Its effect on the rheological and filtration control properties of the formulated mud system was analyzed thoroughly as per API standard procedures. In addition, the shale inhibition properties were investigated with shale recovery test. Further, Core flow tests were carried out to study the formation damage caused by formulated WBDMS. The obtained results revealed that synthesized graft copolymer had shown superior shale inhibition property. The synthesized CMS-g-PAM along with other additives in the developed system had shown remarkable rheological and filtration characteristics. It also exhibited low formation damage, and high shale recovery than the PHPA polymer in the formulated WBDMS. Hence, this synthesized graft copolymer may be used as a potential mud additive in the formulation ofwater based drilling fluid system for drilling the reactive shale formations.
A New Facile Approach to Estimate EOR Polymers Thermal Stability at Harsh Reservoir Conditions
Authors: Zhang Xuan , Han Ming , Fuseni Alhasan , AlSofi Abdulkareem M.
Published: November 2017

Water-soluble polymers have been widely used in chemical enhanced oil recovery (EOR) either independently or part of surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) processes. The polymer viscosifies the injected water thereby reducing displacing fluid mobility and sweep efficiency. Key to efficient sweep is attaining a sustainable mobility control (i.e. maintenance of sufficient viscosity during the propagation in the reservoir). Therefore, long-term stability is a crucial parameter in screening of appropriate polymers for EOR application, especially in high temperature and high salinity reservoirs. Generally, the evaluation of polymer solution's long-term stability is time-consuming process. Accordingly, there is a need to develop fast and reliable means to assess the feasibility of polymers from a long-term stability standpoint. Different from the methods in the literature, this paper presents a new facile approach to evaluate the polymers in powder form and identify their molecular decomposition. The approach is correlated and confirmed against conventional long-term stability results obtained on polymer solutions.

Thermogravimetric analysis (TGA) was used in this work to study the decomposition of polymers and their individual constituents. The derivative of TGA curve with respect to temperature is known as the DTG, which can clearly identify differences in decomposition rates of screened polymers. Furthermore, conventional long-term stability tests were performed on polymer solutions prepared in synthetic seawater with salinity of 57,670 ppm. The solutions were aged at a temperature of 95°C under anaerobic conditions and monitored by rheological measurements for viscosity loss, total organic carbon (TOC) analyses for material loss, and gel permeation chromatography (GPC) for molecular weight loss.

The thermal stability of 12 commercial water soluble polymers was tested in this work. The long-term stability results are consistent with the TGA results. The two polymers showing good thermogravimetric thermal stability exhibited significant viscosity retention in conventional long-term stability tests. TOC and GPC results further supported the TGA results. The developed and demonstrated method provides a fast approach to screen polymer candidates for high temperature and high salinity reservoirs.