bluuebunny/crossref_metadata_2025 huggingface dataset:
BHA Optimization for Surface and Bottom Hole Pressure Control in UBD Wells
Authors: Ge Q. , Shahat A. E. , Kodiah B. N. , Hay M. A. , Al-Hosani M. S.
Published: November 2016

Underbalanced Drilling (UBD) has become a popular technique in oil & gas industry, especially for well-developed hydrocarbon fields to minimize formation damage and maximize productivity. The key in UBD is to control bottom hole circulating pressure (BHCP). To maintain BHCP lower than the formation pressure, a light weight drilling fluid has to be used and probably with concurrent N2 injection. In the case of a tight reservoir, N2 injection rate is increased as high as 1500 SCFM, which will cause severe gas slugging and dramatic standpipe pressure (SPP) reduction when the gas is circulated though the choke. MWD signal will then be lost due to the pressure fluctuation. This paper will present a BHA optimization solution to maintain sufficient and stable SPP during UBD.

Two UBD cases will be discussed. Two main challenges were encountered in the first well: one was to reduce BHCP sufficiently low, the other was to maintain SPP high and stable. To reduce the BHCP, MWD pulser was changed from 180-280 GPM rating to 150-250 GPM to allow lower drilling fluid flow rate and increased N2 injection rate to 1500 SCFM. However, surface SPP dropped significantly due to gas slugging. To avoid this happen, the following optimizations were implemented in the second well: 1) added more HWDPs to reduce internal diameter of the drill string; 2) reduced bit TFA by using less nozzles; 3) installed flow rate restrictor in the drill string.

With reduced flow rate and increased N2 injection rate, BHCP was reduced to 300 psi below formation pressure. At the same time, with the optimized BHA, surface SPP was increased sufficiently to transfer MWD signal continuously. According to the simulation, among the 600 psi increase in surface pressure, 300 psi was from the restrictor, 150 psi was from the change of bit nozzles and 150 psi was from the added HWDPs. The main contribution was from the restrictor. Compared with the first well, which was drilled without restrictor, the data retrieved from the second well was smoother and more readable.

It was the first time that downhole flow restrictor was used in UBD well to maintain SPP. Combined with adding HWDPs and reducing bit TFA, SPP was increased sufficiently, whereby enabled continuous signal transmission and better data quality. Therefore, it is recommended to use this technique in the next UBD campaign.
Statistical Approach to Forecasting Gas-Oil Ratios and Solution Gas Production from Shale Volatile Oil Reservoirs
Authors: Makinde Ibukun , Lee W. John
Published: November 2016

The objective of this paper is to present a new method for estimating producing gas-oil ratios and solution gas production from shale volatile oil reservoirs. In order to enhance our knowledge about the production mechanisms of shale oil reservoirs and possibly better exploit their economic potential, it is important for us to be able to forecast production of the secondary phase – gas.

First, we simulated 30 years' production with different reservoir fluids using a commercial compositional reservoir simulator. We then analyzed producing gas-oil ratio data from several representative oil wells using principal components analysis (PCA). With the aid of the Principal Components Methodology (PCM), the principal components obtained from the analyses were used to forecast gas-oil ratios from wells with production histories ranging from 0.5 to 3 years and results were compared to simulated data. We then calculated the cumulative solution gas production from the estimated producing gas-oil ratios.

Stakeholders often focus on oil forecasts for shale oil reservoirs, ignoring the important solution gas produced from these plays. Limited production data, complex flow mechanisms in liquid-rich shale reservoirs, patterns of producing gas-oil ratios and other factors, make the task of forecasting solution gas production difficult. Principal components analysis (PCA) has enabled us to reveal the internal structure of data from the representative wells considered, in a way that best describes the variance in the data. This allowed us to get principal components (data from the PCA calculations) that helped us forecast gas-oil ratios from shale volatile oil reservoirs using the Principal Components Methodology (PCM). We were able to estimate producing gas-oil ratios and solution gas production with reasonable accuracy.

This work presents a unique and novel approach of forecasting production from liquid rich shale plays. It can help to improve reserves estimation, reservoir management and project economics.
Unlocking Reservoir Potential Using an Automated Multi-Stage H2S Treating Technology - First in Onshore, Kuwait
Authors: Mohammed Tawfik M. E. , Al-Matar Bader , Al-Faresi Fahad A. , Qubian Ali , Al-Shati Abbas
Published: November 2016

Produced fluids, from a number of wells completed in a sour reservoir in a giant field in Kuwait contain varying concentrations of H2S, with levels ranging from 1% (10,000 ppm) to 3% (30,000 ppm).

This souring problem made the concerned reservoir undeveloped fully for many years since there are currently no adequate surface facilities and system in place to handle such high amount of H2S.

In order to dynamically mitigate these challenges, a pilot trial of an innovative technology was considered in one of the wells within this field, which has 1.3% (13,000 ppm) H2S concentration. The outcome from this pilot was very encouraging and promising as the H2S level was reduced to the expected set level on a fully automated basis.

This paper highlights the screening process for candidate selection, technical design considerations, KOC-HSE regulations and the successful implementation of this new system on a single well basis and also the lessons learned from the full collaboration between the project team and service provider.
Waterflood Management of a Super Giant Carbonate Mauddud Reservoir, Raudhatain Field, North Kuwait
Authors: Al-Hajeri Nasser , El-Daoushy Ahmed , Safar Ahmad
Published: November 2016

Raudhatain Mauddud is an oil bearing carbonate reservoir in North Kuwait. Mauddud consists of 10 layers with different fluid properties (API from 30 to 14 Deg). Oil production started in year 1957 till year 2000 when started full filed waterflood project. There was quick and clear positive response to water injection in both reservoir pressure and oil production. However there was early water breakthrough in some wells. Many factors have increased challenges in managing Mauddud waterflood project. These challenges were mainly due to reservoir heterogeneity in all layers, structure, injection of low saline water, difficulty to evaluate remaining potential in flooded wells or to identify thief zone before start the injection.

Consequently, the water management strategy has been adapted by implementing methods and tools to tackle these challenges. Interwell tracers have been implemented to study and monitor water movement from the injectors to the producers and evaluate the sealing nature of the faults. Pattern x-section including Tracer, PLT and production data has been used under one page to assist in evaluating and studying water movement within the reservoir. Automated Workflow has been established to calculate VRR for each pattern. Surveillance plan has been implemented including inference tests and PBU/PFO. The injection to production connections and profiles has been modified by isolating top intervals in the injectors and drill horizontal injectors in the bottom of the reservoir. The new horizontal producer has been drilled in the top of the reservoir with advanced completion technology of ICD.

Managing Mauddud Waterflood project in that way has resulted in increase of total Mauddud daily oil rate by 20% with drop in water cut from 40 to 33%.

This paper is summarizing the methods that have been used to manage Raudhatain Mauddud waterflood project as best practices.
Parallel Flaring Challenges
Authors: Al Aydaroos Salma
Published: November 2016

Flare system in the oil and gas industry is an essential requirement for the continuous safe operation of any processing plant. Flares burn off the flammable gases released from the different pressure sources across the plant via a pressure relief valve returning the system back to operate within its safe pressure limits. In cases where the required flare stack or flare knock-out drum required size and height are big, it can be split into two flare systems operating in parallel. This method of flare design is not common.

In one of the fields, parallel flare design is implemented to operate in 2×50% configuration. Each flare system had its dedicated flare knock out drum. Nitrogen purging only is used as a method to prevent air ingress into the flare. The current configuration has the flares operating at the same time whenever there's any relief to the system. The dependency is on the symmetrical piping to distribute the flow equally to the two flare systems. Here, the positive flow towards both flare systems continuously prevents any air to enter. However, the change in the pressure drop across the flare systems during the relief results in the preferential flow of the relief towards one flare system over the other. This preferential flow results in a vacuum effect occurring through the other flare system. The vacuum effect results in air being sucked in from the flare stack causing deflagration to occur and in some cases detonation.

There are different sealing methods for the flare system and the most preferred method is using liquid seal drum downstream of the flare knock out drum. When designing the flare system, one of the parallel flares should be considered the preferred route for relieving with little or no liquid seal in the liquid seal drum and it's called the primary flare. The other one with a liquid seal height corresponding to the maximum emergency relief is called secondary flare and will only operate simultaneously at any point with the primary flare. The purpose of having a liquid seal drum filled with liquid in the secondary flare is to avoid air ingress. In normal scenarios when relief is channelized through the primary flare preferably, it may induce a suction effect drawing air through the secondary flare which may cause deflagration to occur.

This paper will emphasize challenges of designing flare systems in parallel configuration and the different aspects and considerations of such design.
LWD Sonic Through Casing to Measure Slowness and Evaluate Cement Success While Drilling - A First in Saudi Arabia
Authors: Al-Fawwaz A. , Al-Harbi Z. , Al-Ajmi F. A. , Stolte C. , Razwan K. , Ghosh K.
Published: November 2016

Acoustic measurements are used throughout the lifetime of a well, from seismic to production. Logging While Drilling (LWD) sonic is traditionally used to log formation slowness in the open hole. In this case study we show that both, measuring formation slowness and evaluating the success of a cementing operation can be obtained with the latest generation of LWD sonic tools while drilling, thus saving rig time, simplifying operations, and adding safety to well integrity solutions. Both, formation slowness and well integrity are often an essential criterion for the decision whether to drill ahead or to take additional measures to assure well integrity.

In this case study we have demonstrated that there is additional approach wherein formation slowness can also be recorded/captured in cased hole with LWD tools when the cement bonding is sufficient to allow good coupling. Continuous formation compressional and shear slowness was recorded and extracted for most of the interval below Top of Cement (TOC) and some short intervals above TOC. This advanced technique of logging formation slowness through casing with LWD can complement or even save an additional logging run in some cases and therefore result in significant savings to the operator.

Where azimuthal cement evaluation is not a strict requirement, knowing the top-of-cement (TOC) from LWD can help to confirm well integrity without adding rig-time. Should the measured TOC be lower than required, then more advanced analysis can be run for additional investigation.
An Analyzing Model of Stress-Related Wellbore Strengthening Techniques
Authors: AlBahrani Hussain I. , Noynaert Samuel F.
Published: November 2016

The relatively new concept of wellbore strengthening was introduced to tackle the issues of lost circulation and narrow drilling window complications. Wellbore strengthening is intended to increase the effective formation strength and its resistance to drilling-induced fracture formation. The ultimate goal of this concept is reduce trouble time associa and in many cases, allow drilling to continue past zones that would have required casing to be set in order to proceed. Numerous techniques that vary in their effectiveness and applicability were created. Therefore, there is a clear need for a tool that will help cast a critical eye on the use of these techniques.

The model described in this work aims to provide a practical tool that evaluates and predicts the performance of wellbore strengthening techniques in practical situations. The wellbore strengthening techniques covered by the model use stress changes around the wellbore as the primary criteria for enhancing the fracture pressure and effectively enlarging the drilling window. The model relies on geometric principles, basic rock mechanics data, linear elasticity plane stress theory, drilling fluid data, and geological data. It also provides a process for the proper selection of candidates for wellbore strengthening. To achieve that goal, the model creates all of the possible scenarios in terms of well placement, surface location, and trajectory based on input data to define the scenario that will yield maximum results using a specific wellbore strengthening technique.

The results produced by the model are based on a specific case study. They show practical advantages of applying the model in the well planning phase. The analysis performed using the model demonstrates the applicability of a certain wellbore strengthening technique, the effectiveness of the technique, and the best parameters for the technique. Therefore, the analysis shows not only the best case scenario for applying a wellbore strengthening technique, but it also illustrates the cases where applying the technique should be avoided due to a predicted detrimental effect.

A key finding from the model results is the effect of the direction of drilling on the performance of the highlighted strengthening techniques. It is shown that implementing certain strengthening techniques can cause the paths of the largest drilling window and the narrowest drilling window to switch directions.
Implementation of Transformers On-line Condition Monitoring Systems
Authors: Matar Ghada , Mansour Khalil , Nagpal Sanjay , Alasadi Bashar
Published: November 2016

Transformers are critical to electrical power systems and grids. Their reliability and availability is the key to profitable power generation and transmission. Therefore, the continuous online evaluation of transformer dielectric condition, operation and performance is essential and especially after the new development of sensor and computer technology.

Online monitoring system is also found to reduce maintenance cost, extend life time of the transformer, enhance overload capability, detect faults, and avoid unexpected transformer failures and gird blackout.

The purpose of this paper is to introduce the most recent online condition monitoring systems available in the market and applicable for oil and gas industry.
Engineered Encasement Solution for Cooling Water Line Rehabilitation without Plant Interruption
Authors: Bandopadhyay Surya
Published: November 2016

In the Abu Dhabi Gas Liquefaction Company (ADGAS) owned Liquefied Natural Gas plant in Das Island, Abu Dhabi, the cooling water pipe network consists of cement-lined carbon steel pipes.

The existing underground cooling water (UGCW) networks have been in operation since the commissioning of Das Island LNG Plant almost 37 years ago. The cooling water running through the pipes is untreated sea water.

The pipes are of material grade API 5L Gr B / ASTM A106 Gr B with cement lining thickness of 11mm for pipes above 24" diameter, 10mm for pipes between 24" and 18" diameters and 8mm between 18" and 12" diameters and is routed underground at up to 3-4m depth from the pavement level. On the outer side of the pipes there is protective wrapping of PVC bitumen backed tape.
Hybrid Stochastic Algorithms: A Novel Application in Modeling Facies Cycles and Properties of Carbonate Platform, Onshore Abu Dhabi
Authors: Salahuddin Andi A. , Seiari Jamila M. , Hammadi Khaled E.
Published: November 2016

The carbonate reservoirs lithofacies discussed in this paper contain heterogeneous pore types and properties. The challenge in predicting the distribution of the pores properties is through the technique used to construct a representative model to effectively describe the lithofacies distribution in 3D.

The studied reservoirs are part of the Lekhwair and Kharaib Formations that were deposited in carbonate platform environment varied from lagoon, shoal, to ramp settings during Valanginian-Barremian age. Core and well-log data from an onshore oil field of Abu Dhabi were used to establish lithofacies distribution schemes and high resolution sequence stratigraphy (HRSS) frameworks. Twenty four lithofacies were identified based on faunal content, texture, sedimentary structures, and lithologic composition. HRSS interpretation indicated twenty one fourth-order parasequences that displayed aggradational, progradational, and retrogradational stacking cycles.

A novel stochastic multirealizations modeling of lithofacies and their property distribution has been developed to characterize the subsurface complexity. The method combined depositional environment, HRSS, and diagenesis trend, and then integrated them with dynamic data to generate a holistic reservoirs characterization and representative simulation model.

The workflow is as follows: Detailed core, thin section and lithofacies description;Paleoenvironmental interpretation;HRSS interpretation;Field scale stochastic modeling;Flow simulation and history match validation.

Field wide reservoirs lithofacies and property distributions were modeled and constrained by the identified HRSS framework. Hybrid combination of Truncated Gaussian Simulation (TGS) and Sequential Indicator Simulation (SIS) algorithms were used. This allows generating equiprobable multirealizations of realistic lithofacies cycles and properties trend in the area. The use of lithofacies distribution provided flexibility in the modeling workflow as it offers the outline for rock properties distribution such as rock types, porosity, permeability, and water saturation. The resulting multirealizations demonstrated consistency with the conceptual scheme, outcrop analogs, and geostatistical trend.

This innovative approach has recently been implemented successfully in the studied field reservoirs. The resulting dynamic model depicted a good production history match; hence it will provide reliable production forecast and reservoirs development plan.
Apparent Shear Yield Stress of Filter Cakes Determine Flow Initiation Pressures and Near Wellbore Return Permeabilities
Authors: Suri Ajay , Sharma Mukul
Published: November 2016

Laboratory testing of drilling/drill-in/completion fluids for evaluating formation damage potential requires return permeability tests. It is shown that the apparent shear yield stress of the filter cakes developed by these fluids at the wellbore interface determines the flow initation pressure and the near wellbore return permeabilities during onset of production.

Traditional bentonite clay based and recent non-damaging sized calcium carbonate polymer fluids were chosen to represent the wide variety of water-based drilling and completion fluids used in the field. A standard API filter cell was used with an over-balance of 100 psi and a filtration time of 16 hours for preparing the filter cakes. A constant strain rheometer was used to measure the filter cakes' apparent shear yield stresses. Linear strain and dynamic strain sweep tests were successfully conducted to get the estimates of the apparent shear yield stress of the prepared filter cakes.

Filter cakes prepared with bentonite muds showed an apparent shear yield stress of 800 Pascals (0.12 psi) while filter cakes of typical sized calcium carbonate drill-in fluids showed smaller apparent shear yield stress values between 250 and 450 Pascals (0.06 psi) varying with the median diameter of the calcium carbonate particles. The higher apparent shear yield stress of bentonite filter cakes was attributed to the smaller size of bentonite clay particles (< 2 microns) compared to the drill-in fluid sized calcium carbonate particles (> 2 microns). Two models were developed that used the apparent shear yield stress of these filter cakes and predicted the flow initiation pressures (FIP) and the return permeabilities. The models matched reasonably well with the experimentally measured FIP and return permeability ratios.

A novel approach for measuring and utilizing the apparent shear yield stress of filter cakes is presented that predicts FIP's and return permeability ratios during the onset of production. A new protocol is suggested that measures the filter cakes' apparent shear yield stresses to model the FIP and the return permeabilites for a given drilling and completion fluid.
Challenges and Countermeasures of Directional Drilling Through Abnormal High Pressure Salt/Anhydrite/Calystone Layer in HFY Oilfield of Iraq, A Case Study
Authors: Nie Zhen , Luo Huihong , Zhang Zhenyou , Chen Yufeng
Published: November 2016

The Lower Fars formation located at the depths of 1350-1950meters, it mainly consists of alterations of claystone, anhydrite and salt layer with a 2.22 g/cm3high pressure aquifer in 1400~1600m, the safe drilling window is limited to 0.15g/cm3,the 10~15m interval under this formation is the main Jeribe-Kirkuk reservoir in this oilfield. More than 100 clusters of directional and horizontal Jeribe-Kirkuk wells will be drilled. The high risk of wellbore instability in Lower Fars has resulted in wellhole collapse, overpull, pipe sticking, and sticking during running casing and the high-density salt-saturated drilling fluid is easily deteriorated and loss of liquidity while directional drilling through the Lower Fars interval. In the 1st directional well JKD007, stuck pipe was encountered 3 times and drilling sidetrack holes were required 2 times. In the 1sthorizontal well JK060H,a stuck casing resulted in setting the casing shoe in shallower depth. This study has been carried out in order to decrease the risk of sticking and ensure drilling a smooth, directional hole in the Lower Fars formation. So the lithologic creepage rules and the hole deformation rules in the Lower Fars, major causes for pipe sticking, a safe window of drilling fluid, critical the density of drilling fluid under the different inclinations and technology countermeasures were determined through build the wellbore stability analysis models based on the results of rock mechanics tests of the salt, anhydrite and claystone, the pore pressure, in-situ stress and rock deformation and failure law. The critical density of drilling fluid increase to 2.35 g/cm3 is proposed while the inclination about 35°in Lower Fars formation in order to reduce the risk of pipe sticking; the more stable well trajectory is recommended baesd on the lower Fars deformation rules through adjusting the location of KOP to reduce the inclination and directional length in Lower Fars and considering the distribution of the salt/anhydrite/claystone, and a new kind of the high-density saturated salt-water mud was developed through introducing a kind of new polyamine type inhibitors, synthetic polymer thinner and optimizing the composition and dosage of weighting materials. Since then,11 directional wells and 2 horizontal wells have been drilled and completed with great success for the Jeribe-Kirkuk wells. Average directional drilling time in Lower Fars is reduced from 74days to 59days and the average ROP has improved by 9.64% using a 2.35g/cm3drilling fluid with a controlled viscosity of less than 120s. This paper will systematically describe the details of the sticking mechanism, the Lower Fars wellbore stability analysis method, and the effectiveness of the countermeasures used in directional drilling through the high-pressure salt/anhydrite/claystone layer.
An Integrated Geomechanics and Real Time Pore Pressure Approach helps to Successfully Drill the First Horizontal Well Along the Minimum Horizontal Stress Direction in Tight Sandstone Formations
Authors: Vasquez Vladimir , Roux Stephane Le , Heylen Julien , Eissa Hassan , Almazaqei Akram
Published: November 2016

An operator in the Middle East is seeking to develop its natural gas resources to meet rising energy demand. This operator is drilling horizontal wells along the minimum horizontal stress direction in an attempt to generate multiple transverse fractures during stimulation to increase gas production in unconventional reservoirs. However, drilling operations in these wells is extremely difficult because of the in situ stress environment; these conditions result in a significantly increased number of stuck pipe incidents, wellbore collapse, incurring remarkably high nonproductive time. This paper describes the methodology used to define and calibrate the safe mud window for the curve and lateral section of the first horizontal well drilled in tight sandstone formation by conducting a wellbore stability study and real time drilling geomechanics and pore pressure monitoring. The wellbore stability study incorporates all logs and rock mechanical properties propagated on the direction survey and proposed formation tops of the planned horizontal well X-56. The well was drilled successfully with a mud weight of95 pcfto 98 pcf in the curve section and 100 pcfto 106 pcf in the horizontal section. Major technical contributions of this paper include: (1) Characterization of geopressures and stress field in different formations calibrated with real time data, (2) back analysis methodology to estimate fracture gradient from formation integrity test (FIT) & image logs, in addition to this (3) pore pressure zones designation along the stratigraphic column.
Achieving 50% Plus Oil Production in Asphaltene-Stabilized Emulsion Problematic Field Under Artificial Lift Operation
Authors: Furuichi Naoto , Uetani Takaaki , Yorozu Hirokazu , Sasaya Kazuyo , Shibuya Takehiro , Kiminami Narihito , Yonebayashi Hideharu
Published: November 2016

An oil well in Japan, referred to in this paper as Well B, experienced emulsion problems from the commencement of natural flow production in January 2008. These problems were immediately resolved by the usage of effective demulsifier which was selected through bottle tests. As the well ceased to flow naturally in April 2014, an artificial lifting operation began with a jet pump since July 2014 to maintain the production rate. Shortly after artificial lifting performed, serious emulsion problems recurred even though it was continued to utilize the demulsifier which had worked successfully during natural flow.

This paper presents the details of how we addressed these problems and managed to continue operations. Temperature, retention time and chemical injection were well known as the factors for separating emulsion. First, plant operator planned to raise the processing temperature from the current operating condition of 60°C. However, it was found that temperature higher than 60°C could damage coating inside gun-barrel and tanks which were located downstream of the second separator. Through fine optimization, the processing temperature was set at 65°C not to expose them to higher than 60°C but this was not feasible to separate emulsion. Second, we changed the flow scheme of two production separators from parallel to series connection. This countermeasure didn't resolve these problems essentially but it enabled us to catch almost all emulsions at the first separator. It means that the first separator condition could be reset by draining emulsion periodically from dump valve so that we managed to continue operations with keeping the target water content in sales oil. Finally, a series of bottle tests were conducted to select a better demulsifier to replace the original one, which was no longer effective. Soon after injection of the new demulsifier, the emulsions disappeared and the operator regained the production rate.

This improvement reduced the emulsion disposal cost and man-hour for treating emulsions. Furthermore, oil which had been disposed as emulsions could be sold as product and Net Present Value (NPV) of this asset increased through high production rate operations. The total amount of economic impact reached 2 million dollars.
Control of Contaminates & Degradation Products in Amines During Sour Gas Treatment
Authors: Singh Sanjay Lallan , Veerakumar Ukkirapandian , Abbas Ahmed
Published: November 2016

Objectives and Scope

The objective is to control contaminants in amine systems such as heat stable salt, degradation products, hydrocarbons, particulates and injection chemicals etc. through chemical analysis and process operation. Interpretations of lab results and corrective action in plant to help us to monitor, control and improve the performance by minimizing loss of amine in the system.

Methods, Procedures and Processes

Contaminants are substances which enter the process and "pollute" the amine. Amine contaminants can be grouped into five categories; (1) Heat stable salts, (2) Degradation products, (3) Injection chemicals, (4) Hydrocarbons and (5) Particulates. Degradation Products are contaminants in solution where the molecule is broken down or changes its chemical form. Amines considered for this study are Diethanolamine (DEA) used in LNG plant and Methyl diethanolamine (MDEA) used in OAG and IGD plants. Amines should be color free and devoid of particulate matter. This is achieved through activated carbon and mechanical filters so that amine quality is within established limit.

Results, Observations and Conclusions

Laboratory analyzes amines sample (DEA & MDEA) for various contaminants by simple analytical techniques using titrators, pH meter and Gas chromatograph. The analytical data for amine strength since 2013 i.e. in case of DEA the average is 20.1 % within the range of 18-22 % and for MDEA, the average is 45 % and the range is 40-50 % with marginal exception on some occasions. The foam tendency and foam stability data for last three years are optimum indicating minimum contamination. Chloride and Iron which are precursor to HSS & degradation products are monitored on monthly basis and are well below the maximum control value. HSS in amines were low which indicates the stability of amine. The lean amine after regeneration to strip out H2S and CO2 is passed through mechanical filter to remove fine particles and suspended solids which is further treated through activated carbon filters to remove hydrocarbons, anions, cations, impurities etc. Laboratory analyses are vital links for smooth operation of amine system. Simple chemical analysis helps us to understand and give timely response for process control. Historical data gives the perspective for spotting trend of sampling, analysis and possible errors.

Proper design of mechanical and carbon filters helped us to maintain amine system free of contaminates and healthy minimizing amine loss. The low level of contaminants in amine system ensures integrity of process equipment and associated units.

Novel/Additive Information

This simple analytical techniques and process control helped us to maintain the quality of amine and integrity of plant. The same approach is applicable to any gas treatment plant and can be applied there.
Advances in Pulse Neutron Capture in Evaluating Formation Properties within Low Permeability Carbonates Reservoir Onshore Abu Dhabi: An Integrated Case Study
Authors: Khan Muhammad Faisal , Ashqar Ayham Al , Rawahi Ali Salem , Gashut Mohamed , Hammadi Khaled Eissa
Published: November 2016

Pulse neutron capture (PNC) is an effective technique to monitor lateral and vertical saturation/sweep. Assessing pulsed neutron results in either open-hole (OH) or cased-hole (CH) is key in evaluating formation properties, while with reservoir performance routinely monitored, time lapse logs are compared with the base logs to dynamically assess saturation changes and sweep efficiency.

PNC sensitivity to factors such as invasion, bore-hole and cement; makes its result influenced by rock matrix and fluid properties. LWD logging may minimize the mud filtrate impact; however this is subject to the drilling parameters and exposure.

LWD PNC has been analysed (drill and wipe pass) in both oil and water base muds. Quality assessment is performed on LWD/WL Sigma considering: mud used, invasion, formation water and mud properties. Variable Sigma was used to improve PNC saturation interpretation particularly within the transition zone. The effect of mud was discussed with examples showing its impact on data properties.

WL PNC time lapse logging over five years were analysed, results indicated mud dissipation process masking formation response. Resistivity and pulse neutron saturations are compared. PNC saturation is integrated with resistivity based saturation.

The capability of the pulsed neutron logging to derive meaningful results within the studied fields were examined in both OH, and CH conditions along with the definition of base log and the parameters used to derive saturation. Variable Sigma concept and uncertainty within transition zone is discussed. The used methodology and integration has improved the interpreted saturation, consequently enhanced the reservoir management.

The data used within the paper comes from two different carbonate fields' of complex, heterogeneous pore structures, and diverse mineralogy, allowing generic approach to the drawbacks seen.
First MLTBS Level 5 Installation for Operator in Abu Dhabi
Authors: Elsayed Mohamed Ibrahim , Abdulhalim Abdallah , Al-Mutairi Ali Mohamed , Saqib Talha , Sabri Abdul Moez , Karrani Saud Mohamed , Ponton Calvin , Rosas Eulalio , ElSin Rami Samir
Published: November 2016

A major Abu Dhabi oil and gas producer targeted an increase in production from their major offshore oilfields. Better optimization of the reservoir through advanced well architecture was considered an option. One way to achieve this objective was through accessibility and hydraulic control of all horizontal drains. Multilateral technology is commonly used to increase the production per well and reduce drilling time while optimizing production facilities. The project targeted multiple reservoirs with two separate laterals to meet reservoir requirements. The application required individual through tubing access for intervention into each lateral. Multilateral technology has been traditionally limited to commingled production with limited or no access to the laterals. To help address and overcome these challenges, the operator planned and installed their first Level 5 multilateral tieback system (MLTBS).
Specifying CO2 Compressor
Authors: Desai Manthan G.
Published: November 2016

Objective / scope

This paper highlights the care to be taken by an Engineer while specifying and selecting a centrifugal compressor for CO2 compression.

Methods / Procedures / Process

With the increase in the levels of CO2 in the atmosphere, there is an increase in the popularity of capturing CO2 emitted from the large source points such as fossil fuel power plants, steel mills, cement plants, etc. before its release to the atmosphere and storing it under the geological formations (also used for Enhanced Oil Recovery (EOR) where possible). The compressors used to transport and store the CO2 at such depths need to compress the gas from atmospheric pressure to the pressures of the order of 200 bars or more.

Results / observations / conclusions

The critical temperature of CO2 is only 31.1 deg. C, so the CO2 is generally transported and stored in supercritical state. The thermodynamic properties of supercritical CO2 are considerably different from the other real gases generally compressed. Further, to achieve this supercritical state, the critical point of CO2 is crossed somewhere in the compression stage. Near critical point, the ideal gas laws will not hold good for CO2. Moreover there is a reduction in the choke margin of the compressor due to the reduction of the sound speed in CO2, particularly near the thermodynamic critical point. Also the CO2 compressibility and specific heats are not linear near the critical pressure and temperature. The impurities in the CO2 will further affect the thermodynamic characteristics of the working fluid. Also the water content in the CO2 makes it extremely corrosive.

Novel / Additive information

Considering all the aspects mentioned above, specifying the CO2 compressor correctly in terms of the equation of state to be used, the interstage pressures and temperatures to be maintained, suggesting the number of impellers per stage to maintain the desired flow coefficient, metallurgy to be selected and scheme of compressor dry gas seals, etc becomes all the more important and are described in the paper.
Unlocking Profitable Production Opportunities Based on Mature Common Field Proven Subsea Control Components
Authors: Elsabbagh Sameh
Published: November 2016

In deep water, subsea approach is often non debatable. Besides, subsea solutions are often selected because a platform-based development would not be profitable. However, due to very large combinatorial size of the design and operational decision space for the Platform versus subsea solutions, the selection between Platform and subsea solutions is a matter of doubt unless having large reserves or complex reservoir.

Based on experience acquired through various subsea gas projects, the paper outlines some standard blocks for subsea production system based on mature and field proven components. In this context, flexible architectures along with Tie-back options with existing infrastructure and its related de-rating will be illustrated. Subsea gas compression standard template solution along with its control system requirement will be overviewed. Key factors are highlighted in order to take sufficient account of options value. This will be very helpful for concept selection especially for stranded/ marginal fields allowing unlocking of new opportunities for profitable production where shallow water subsea systems can be an ideal solution for improving net present value.
Improved Workflow for Characterizing Complex Carbonate Reservoirs
Authors: Smart Charles , Mohnke Oliver , Bhatt Pranjal , Fernandes Warren , Salter Tim , Ping Tian , Jin Ou , Mohamad Faisal , Saeed Ismail , Hasani Majid
Published: November 2016

Understanding the hydraulic properties of reservoir rocks is crucial for estimating reserves or managing storage and production of a reservoir. In reservoirs containing complex carbonates, rock-typing methodologies that recognize multimodal porosity have been widely used. A new rock-typing workflow based upon Thomeer-buoyancy modelling is presented, with proven application in Middle Eastern carbonate reservoirs where multimodal porosity is observed.

Porosity reflects the total pore volume of the rock, but fluid transport within the media rock unit is dominated by the fractional pore volume connected to the largest pore throat system. The mercury intrusion capillary pressure (MICP) experiment alone provides insight into the connected porosity and permeability volumes. In addition, the MICP experiment establishes the relationship between the vertical saturation profile of the wetting and non-wetting fluid phases. A workflow that captures the buoyancy of the fluids (saturation-height) alongside this pore volume complexity can then provide insight into the pore geometry, saturation distribution and permeability of the investigated reservoir volume.

This workflow is distinctive because it integrates reservoir physics with new analytic approaches that include a routine conversion of properties from ambient to reservoir conditions, a fully automated Thomeer deconvolution of mercury injection experiments (THOPAL) and a Thomeer-buoyancy analytical solver for properties estimation in the log domain.

The solutions provided comprise continuous magnitude and category estimations of 1) permeability at reservoir conditions and Thomeer coefficients (G,Pd and Bv), 2) statistical uncertainties of the previous, 3) continuous scalar results in the hydrocarbon column including reservoir capillary pressure, bulk volume oil and Sw as well as probabilistic pore geometry grouping.

Two case studies are presented to demonstrate the application to wellbores within the investigated Middle Eastern carbonate reservoirs.
Ultra-Sour Natural Gas Sweetening Using Membranes/Amines Hybrid Systems for Recurrent Middle East Conditions
Authors: Alkatheri Mohammed , Grandas Ricardo , Betancourt-Torcat Alberto , Almansoori Ali
Published: November 2016

Recently an increasing number of countries have expressed their concerns over meeting their future gas domestic demands and export commitments. This tendency is particularly palpable in the Middle East countries. Thus, the region's gas producers have been compelled to develop unconventional ultra-sour gas fields previously considered uneconomic due to technical challenges. Conventional gas processing considers chemical absorption methods using solvents (such as an alkanolamine) for acid gas (e.g., H2S and CO2) removal. However, new polymeric membranes for bulk H2S removal from both very high H2S content gas and operating pressures have been recently developed. These recent developments can contribute to the treatment of unconventional ultra-sour gas or retrofitting existing plants. Accordingly, the present study analyzes a hybrid sour gas sweetening system consisting of two stages. In a first stage, a membrane system is used to reduce the inlet feed gas bulk H2S and CO2 concentrations. Consecutively, the sweet gas product final specifications are met using an amine-based system. Ultra-sour gas (e.g., 25% H2S) is considered to be treated. The study uses a simulation-based optimization approach. The proposed hybrid process was simulated using ProMax® v3.2. The ultra-sour gas conditions are uncommon on a global scale, but they can be found recurrently in the Middle East. The simulation results show that the operating and capital expenditures of the process can be reduced using a hybrid system.
Deciphering Intrinsic Fluid in a Low Salinity Sandstone Reservoir to Optimize Reservoir Management Development Strategies
Authors: Rabba Ali S. , Madani Sultan S. , Zeghlache Mohamed Larbi
Published: November 2016

Fluids identification in reservoirs that bear low or mixed formation water salinity poses a challenge for reservoir management in terms optimum well placement strategies and reservoir surveillance. The logging industry provides many technologies to help characterize in-situ fluids while drilling or during the production stage.

An integrated reservoir engineering team has established an integrated formation evaluation methodology to identify fluids encountered in the reservoir, while drilling or while monitoring saturation changes periodically in key observation wells. A number of new and re-entry wells were selected to measure fluid saturation while drilling via different saturation tools; namely, resistivity, nuclear magnetic resonance (NMR), formation pressure testing and fluid sampling, and advanced mud gas logging to complement each other. Carbon/oxygen (C/O), coupled with a flowmeter survey, were run in two observation wells, in both flowing and shut-in conditions, and showed positive results for enhacing the capability to monitor saturation.

Following a comprehensive evaluation of all acquired data and interpretation, the petrophysical model was calibrated using NMR and downhole fluid samplings. Results have enabled building fluid characterization criteria for low contrast salinity clastic rocks based on reservoir complexity and fluid uncertainty.

The optimized C/O acquisition helped with analyzing fluid saturations and building an intriguing process to address challenges related to different environmental conditions. This evolved methodology revealed a more consistent saturation mapping with the actual reservoir understanding while identifying the optimum completion and excellent wellbore conditions for such a method.

The established fluid identification process, while drilling, will help optimizing well placement and well completion to yield productive wells. The customized C/O log process will enhance reservoir surveillance and monitor saturation change to assess sweep efficiency and overall field performance.
An Effective Approach for Uncertainty Analysis and Workflow Optimization in Undeveloped Reservoir
Authors: Buzdar Mudassir , Ali Mohammed , Hussain Amjad , Arif Naveed , Bughio Shamsudin
Published: November 2016

Subsurface appraisal activities are employed to reduce reservoir uncertainties. Field appraisal/delineation is crucial to understand the subsurface complexity and define the extent of reservoir. In such scenarios, the ability to appropriately characterize reservoir is a primary factor that determines economic viability of a development project. The high cost associated with appraisals of petroleum fields requires manageable risk and uncertainty quantification. Often, results from appraisal campaigns are not enough to reasonably justify decision of developing the field.

An efficient methodology for quantification of subsurface uncertainties during the appraisal stage was implemented to frame the objectives for achieving optimum outcomes. The approach is more systematic in comparison to classical methods to gain better understanding of uncertainty parameters, capture level of uncertainty and identify optimal model for the field development. Production forecast using probabilistic approach provides good estimate of cumulative oil or recovery factor considering the impact of uncertainties and risk.

This study employs uncertainty quantification and optimization workflow for assisted history matching and forecast during appraisal stage. Uncertainty parameters with ranges and distribution, response parameters along with criteria set were framed into the workflows of sensitivity, history matching and uncertainty analysis. Experimental design techniques (OVAT and Latin Hypercube) were used for sensitivity analysis and uncertainty parameter reduction. Objectives set for scope of studies were driven with detailed analysis of the simulation runs and successfully culminated the promising results within specified project time duration.

The methodology is applied to onshore field in the Middle East during the appraisal phase with limited wells.