bluuebunny/crossref_metadata_2025 huggingface dataset:
Fracture Cleanup Determination by Guar Measurement in Flowback Water Samples
Authors: Al-Saihati Ali H. , Hajj Hicham El , Ortiz Rick , Bittar Michael , Shakeel Muzzammil
Published: March 2015

Hydraulic fracturing is a well stimulation process used to maximize production of oil and natural gas. It is used to create new fractures and enhance in-situ subsurface fracture systems as well to allow oil or natural gas to move more freely from the rock pores to the production wellbore. The post-fracturing flowback procedure is critical to the production performance of a fractured well. An improper flowback cleanup often leads to lower retained conductivity near the wellbore, resulting in reduced production. Controlled flowback is beneficial for properly removing polymer gel residue from the proppant pack. The degree of propped fracture cleanup is related to a number of factors that relate to the measurement of guar polymer contained in the fluid flowback samples. Measurement of guar carbohydrate from fluid flowback samples is used to estimate the amount of guar recovered after fracturing treatments. Using a field study and laboratory analysis, this paper demonstrates that the measurement of the guar polymer in fluid flowback can be used as an indication of fracture cleanup. The Anthrone method, a technique for measuring total guar carbohydrate in the fluid flowback samples, is used. Anthrone dissolved in sulfuric acid forms a yellow solution. In the presence of guar or its derivations, the solution turns green/blue. Using an ultra violet (UV) spectrometry technique, guar concentration in the fluid flowback samples can be determined from the intensity of measured color. Many fluid samples collected from two wells were analyzed and results are presented. A good correlation between the guar polymer concentration and cleanup is observed and quantified. Results from this study show that using this technique can result in an optimum flowback design that maximizes near-wellbore (NWB) conductivity and fracture cleanup for better production.
Design, Execution, and Results of the First Multi-Zone Cased Hole Gravel-Pack Completion in West Malaysia
Authors: Hareezi Adam , Hamid Afiq B , Samuel Orient B. , Syafei Djuhana B , Khalid M Zaidan , Jabar M Zawawi , Abidin Reduan Zainal , Noorizan Airin Basha , Gil Joel , Saebi Shahryar , Wallace Cal , Sharji Nasser As , Khai Tan Chun
Published: March 2015

This paper illustrates the design and application of tools and procedures for successful execution of the first Multi-zone Cased Hole Gravel Pack Completion in West Malaysia utilizing Alternate Path (Shunt Tube) Technology with Isolation System to enable access to multiple reserves and maximize reservoir contact in “A” field.

The single trip gravel pack system allowed multiple stacked zones to be completed with reduced completion operation time. The “A” field, predominantly consisting of unconsolidated stacked layers has tendency to produce formation fines and sand and historically, gravel pack has proved as the most appropriate sand exclusion method for this field. Considering the distance between the adjacent zones (upper zone was approximately 120m distance from the middle zone), shunt tube technique was selected as the most suitable method for achieving uniform and high packing efficiency.

Several options were examined for the completion to select a technology to have a proven cost effective solution to cope with different intervals space out far distance. The multizone shunt tube system has an intensive record of accomplishment in the oil and gas industry and has been used in Malaysia with excellent results. It was a very attractive technique to use because of its simplicity and cost-effective approach of completion of multiple intervals. Proppant placement with 100 percent packing efficiency along 227m of 3 different zones was critical for the success of the project. Shunt tube configuration was optimized by selectively plugging and unplugging nozzles to efficiently distribute the proppant to all 3 intervals. This technique added high value to the success of the operation and ensured any bridges in the annulus were bypassed during gravel packing treatment.

The gravel packing carrier fluid also plays an important role when using shunt tubes. The system needs a viscous fluid to suspend and carry proppants to the perforations and form a competent and compacted pack without damaging the treated zones. For this reason, a Non-polymeric and solid free VES (viscous elastic surfactant) was chosen. The selected carrier fluid has been used in propped fracturing as well as gravel packing with excellent results as it has exceptional gravel carrying capability and leaves high formation retained permeability resulting in significantly low skin due to the unique capability of breaking when exposed to small amount of liquid hydrocarbons thus eliminating the requirement for breakers (Sullivan et al, 2006. Parra et al, 2009. Shahryar et al, 2010).
Artificial Intelligence Based Estimation of Water Saturation Using Electrical Measurements Data in a Carbonate Reservoir
Authors: Bageri B.S. , Anifowose F.A. , Abdulraheem A.
Published: March 2015

Good estimation of water saturation is necessary for successful estimation of reservoir properties as it minimizes the error in initial oil-in-place calculations. Electrical measurements on core plugs have been used to predict water saturation by analyzing the parameters of Archie's equation. Presently, several methods such as conventional, CAPE (1, m, n), CAPE (a, m, n) and 3D methods have been used to analyze the parameters. However, the accuracy of these methods has become inadequate for optimal estimations. Recent successful applications of Artificial Intelligence (AI) techniques in petroleum engineering have confirmed the capability of AI to handle such non-linear and complex industrial problems. Interestingly, the new paradigm of employing AI for water saturation estimation has not been sufficiently addressed in the petroleum engineering technology application literature.

This study focuses on the use of the predictive capabilities of Artificial Neural Networks and the Fuzzy Inference Engine. 378 data samples obtained from the laboratory measurements of electrical properties of 41 core plugs taken from Carbonate reservoir rocks in the Middle East were used for the implementation of the proposed techniques. Using the popular stratified data sampling method, 70% of the data points were used to train the AI models while the remaining 30% were used for validation and testing.

The comparative results showed that the AI models performed better with higher accuracy and lower errors than those obtained with the current methods. Based on this result, we conclude that Fuzzy Logic exhibits a robust predictive capability for the estimation of water saturation from electrical measurements by providing a good match with the core values and giving better error distribution than the other AI and current methods.
Water Complex Permittivity Model for Dielectric Logging
Authors: Donadille J.M. , Faivre O.
Published: March 2015

In recent years, high-frequency dielectric tools have become an increasingly accepted service for providing saturation, water salinity, and textural information. To obtain these petrophysical quantities from the measured dielectric data, a mixing law is used that relates the bulk formation complex permittivity (relative permittivity and conductivity) to the constituents of the system, including the water present in the pores. Several mixing laws have already been published in the literature. This paper is concerned with an integral part of all of them, which is the prediction of the water complex permittivity as a function of salinity, temperature, and pressure.

The water complex permittivity is known to vary with salinity, temperature, pressure, and frequency of operation. We have established a dielectric water model as a function of these four quantities, and have recently validated this model with dielectric laboratory experiments on several water samples at high temperature and pressure. In this paper we fully disclose the model so that it can be used and adapted by the industry.

We also demonstrate with a sensitivity analysis that using the correct water model is critical to the accuracy of the final petrophysical outputs.
Case History: New Horizons for Downhole Flow Measurements via Coiled Tubing Equipped with Real-Time Downhole Sensors at South Ghawar Field, Saudi Arabia
Authors: Buhassan Shaker , Halder Surajit , Tammar Hassan , Beheiri Faisal , Ahmed Danish , Brown George , MacGuidwin Jeffrey Thomas , Haus Jacques , Moscato Tullio , Molero Nestor , Manzanera Fernando Baez
Published: March 2015

During the last 5 years, one of the most common matrix acidizing enhancement techniques used to improve zonal coverage in open hole or cased hole wells is conducting a distributed temperature survey (DTS) using coiled tubing (CT) equipped with fiber-optic and real-time downhole sensors during the preflush stage before the main stimulation treatment. This is used to identify high and low intake zones so the pumping schedule can be modified to selectively place diverters and acidizing fluids with a high degree of control. Once stimulation treatment has been completed, a final DTS analysis is performed to evaluate the zonal coverage and effectiveness of the diversion. Even though this technique has provided satisfactory results, alternative methods providing faster and more accurate understanding of flow distribution between the zones and laterals are needed, especially if there is limited temperature contrast between fluids and reservoir. Thus, an innovative coiled tubing real-time flow tool has been recently developed to monitor flow direction and fluid velocity. This measurement is based on direct measurement of the heat transfer from the sensors to the surrounding fluid using a calorimetric anemometry principle. The first worldwide use of this technology in a Saudi Aramco injector well showed this to be a viable new approach to downhole flow monitoring that can be used by itself or in conjunction with DTS, depending on the constraints of each individual intervention.
Mechanical Properties of Carbonate Formation and Their Influences on Drilling and Hydraulic Fracture Modeling
Authors: Hamid Osman , Rahim Zillur
Published: March 2015

Among many challenges encountered during drilling and hydraulic fracturing operations in carbonate reservoirs, wellbore stability related issues while drilling and variability and unpredictability of the outcome of hydraulic fracturing are the most significant ones. Accurate characterizations of the mechanical properties are essential to understand how the carbonate reservoirs respond to these issues. Static mechanical properties can be obtained directly in the laboratories from triaxial tests on core samples, while dynamic properties can be calculated from wireline measurements such as acoustic wave velocities and bulk density of the formation.

Core plug samples from Field-A producing carbonate B and C reservoirs were tested for acoustic and mechanical properties using triaxial method. Laboratory studies on the elastic and deformational properties of carbonate B show that this formation exhibits wide range of elastic properties due to heterogeneity, while the trend in carbonate C is much clearer.

This study enabled the generation of empirical correlations among different properties, such as density and P-wave velocity, P and S-wave velocities, P-wave velocities to static and dynamic moduli and Unconfined Compressive Strength (UCS). The correlations show a good agreement with available correlations that are commonly used in the industry for carbonate C. The developed equations will improve and enhance hydraulic fracture and wellbore stability models that are related to geomechanics in the carbonate reservoir. The equations compute the mechanical properties for any well within the study area using measured geophysical log data such as density and compressional and shear sonic logs. The derived correlations are implemented in actual cases and are presented in this paper.
Challenges and Solutions to the North Kuwait Jurassic Dynamic Modeling
Authors: Sharifzadeh Ahmad , Daoud Ahmed , Amari Mustafa , Dashti Qasem , Al-Enzi Bashayer
Published: March 2015

North Kuwait Jurassic Complex consists of 6 fields with 4 major reservoirs. Total of 19 integrated reservoir models incorporating seismic, geological, petrophysical, and engineering data have been constructed to delineate the reservoirs and perform multi-scenario production forecast for the whole field. These models are dual porosity, with near critical fluids of gas condensate and volatile oil. There are different challenges to model the whole fields that can be summarized as follows. First, the two main producing reservoirs among all fields are (RA) and (SA) which account for about 40% of the hydrocarbon in place. These two fields show existence of different free water levels (FWL) along the areal extension of both fields without any evidence of compartmentalization based on pressure data. Second, all the asset is producing towards one common facility where some fields are gas condensate and some other is volatile oil. Third, modeling the fields using compositional simulator with dual porosity system will complicate the models and increase the running time.

This paper explains the approach adopted to solve most of these challenges. First, a numerical approach was implemented to allow communication between these blocks of different FWL's at the hydrocarbon zone only. Thus, ensure the equilibration of the system with honoring the geological understanding and allowing pressure communication through the hydrocarbon leg. Second, a proposed approach of using the standalone simulation models for running different sensitivities to select the optimum development plan per each field and then couple them with one controller at the surface to get the optimum field development plan for the whole fields as one asset producing through one common surface facility. Third a black oil delumping approach was used to convert the black oil to 35 pseudo components based on different EOS models generated per each field. Thus getting the advantage of speeding up the run based on using black oil simulation and reporting the change in composition with time using a simple black oil delumping look up table.
Risk Assessment Suite - An Innovative Approach of Risk Mitigation Measures Prioritization for Well Integrity Assurance
Authors: Amrideswaran Hareesh , Al-Sada Abdulhameed Ali , Saleh Mohammed Ali Abdulla
Published: March 2015

Well Integrity Assurance is the key concept to reduce the risk of unwanted incidents in any oil & gas field, thereby ensuring safety of people, environment, assets, business and reputation during the entire well life cycle from Conception to Abandonment. Due to a huge number of wells and the ever-increasing matured field issues, the key challenge faced by Qatar Petroleum was to prioritize the remedial measures (rig & rigless) and pro-active health checks based on well risk conditions and barrier status. In this paper, we are elucidating the Risk Assessment Suite created by the Well Integrity Department of Qatar Petroleum to resolve this challenge.

The Risk Assessment Suite is an innovative model to assess the integrity issues in oil/gas wells, to establish their associated risk level and to prioritize the mitigation measures/pro-active health checks in those oil/gas wells based upon the risk level and optimum available resources for ensuring that the wells operate in a safe operating envelope. The four major components of the risk assessment suite are Risk Ranking Guidance Matrix, Well Failure Matrix, Priority Ranking Matrix, and Well Risk Assessment Sheet.

The Risk Assessment Suite is a highly successful methodology practiced in Qatar Petroleum for assuring safety, well integrity, higher return on assets and performance enhancement of its oil & gas fields. The highlight of this suite is its unique innovative model for prioritizing the rig/rigless repairs and pro-active routine/non-routine health checks by considering priority ranking points together with risk ranking as a single function in order to address both risk level and the barrier failure intensity of a well at the same time.

Risk Assessment Suite is a highly transferable model that can be used by other E&P companies worldwide with similar requirements like Qatar Petroleum for prioritizing remedial measures and risk mitigation actions on oil/gas wells in their fields.
A Slow Release CO2 for Enhanced Oil Recovery in Carbonate Reservoirs
Authors: Alam M.M. Mansoor , Mahmoud Mohamed , Sibaweihi Najmudeenn
Published: March 2015

CO2 is used to swell the oil and increase its mobility by reducing the viscosity and reducing the IFT between the rock and oil. The problem of CO2 during the EOR process is the gravity override and the displacement efficiency. Foamed CO2 was introduced to overcome the displacement efficiency problem. The foam can be generated using different types of surfactants. The surfactants will not from a stable foam at HPHT conditions and the reservoir water salinity will impact the foam quality in addition to the surfactant adsorption to the carbonate rocks will reduce the surfactant concentration and will affect the generated foam.

In this study we will investigate the use of slow release CO2 concept. The CO2 can be slowly released in the carbonate reservoir by injecting low reaction rate fluids (in this case citric acid) that will react with the rock after placement and this will generate CO2. Coreflooding test will be performed using carbonate core at 100°C saturated with crude oil. CMG will be used to simulate the process of CO2 generation by injecting the CO2 in an aquifer underlying the carbonate formation and after that allow the CO2 to release to the oil zone. The slow released CO2 from the aquifer will swell the oil and then the oil can be displaced by sea water.

Coreflooding results showed that the slow release CO2 technique gave up to 42 % extra oil recovery from the oil in place after sea water flooding into the carbonate core at 100°C and 1100 psi back pressure. The extra oil recovery was due to the slow resealed CO2 and oil swelling and also due to the rock dissolution and IFT reduction. The simulation results by CMG showed that the slow release CO2 technique gave 70% oil recovery from the residual oil more than the sea water injection which confirmed the efficiency of the slow release technique in large scale.
Nano-Confined Adsorbed and Free Gas in Shale Reservoirs: A Molecular Dynamic Study
Authors: Stukan Mikhail , Abdallah Wael
Published: March 2015

Gas production from shale reservoirs is expected to last for hundred years by some estimates. However, the phase behavior of gas in shale reservoirs is inherently more complex compared to the conventional ones. In shale reservoirs, a large amount of gas is stored in nano-size pores which are an integral part of kerogen structure. The phase behavior of this fluid is significantly different from those in the bulk and is still far from being fully investigated. Better understanding of the influence of nano-confinement on the fluid phase behavior should help in estimating the amount of gas in place and to develop an optimum production plan to maximize the recovery.

Using molecular dynamics simulations, we modeled methane's phase behavior in shale gas reservoirs wherein the nano-pores in the kerogen play a major role in adsorption of the gas molecules. A fully atomistic model was used for methane and the pore walls; the pore walls were represented by graphite sheets. Eight pores of width ranging from 0.7 nm up to 4.0 nm were considered; the pores were connected to a bulk volume (reservoir). The amount of free and adsorbed gas in the pores was calculated in the pressure range from 6000 to 100 psi.

The results demonstrate the influence of pore size on the mechanism of gas release and its dynamics. The gas production rate from pores is a result of the interplay between the rate of transport of a free gas molecule out of the pore, and the rate of desorption of the adsorbed gas from the pore wall. For the smallest pores, adsorption plays the main role in controlling the dynamics as compared with the large ones. Our data can be utilized for predicting the rate of gas production from shale gas based on the pore size distribution and fluid composition.
Selection of Best Reserves Estimation Methodology to Quantify and Reduce the Uncertainty – Accompanied by Çayirdere Gas Field Case Study
Authors: Tugan Murat Fatih , Onur Mustafa
Published: March 2015

Uncertainty in reserves estimation plays a critical role at all-time steps of production/development plans and determines the financial strength of the project and the company. In this study, the importance of probabilistic approach to reserves estimation is emphasized by showing change in the estimated values of reserves with producing time. An analytic uncertainty propagation method (AUPM), a simple, yet quite accurate alternative uncertainty quantification method to the well-known Monte Carlo method, is used to assess the uncertainty in gas reserves estimations. In addition to the theory, as a case study, one of the largest Turkish Petroleum Corporation (TPAO) gas field, Çayırdere Field, reserves is estimated, and uncertainties for this field reserve are presented at all-time steps. As a result, the estimated value of the most likely reserve (P50) by utilization of AUPM in conjunction with probabilistic methodology prior to production period, matches quite well with the value estimated at the abandonment of the reservoir by using performance-based methods. The Çayırdere Gas Field Case Study supports the glorious success of the approach promised in this study.
Renovating Bahrain's Field: Improving Production Testing Efficiency
Authors: Naser H.H. , Zainal Y.A.
Published: March 2015

Production testing of wells in Bahrain field historically was carried out at Well Manifolds using 2-phase test separators, mechanical liquid meter and gas chart recorder. Flow line liquid samples were collected for water cut measurement. Production fluid was diverted to test separators using manually operated valves on production and test headers. When Tatweer Petroleum took over operation of Bahrain field in late 2009, there was a need for more well testing to improve surveillance of wells performance and accommodate new wells added through aggressive drilling program. This was possible through contracting well testing services to assist in handling the increased number of well tests and also validate tests of the company owned Test Separators.

In 2012, 3-phase test separators were introduced as replacements to the old, undersized 2-phase test separators. The new separators are equipped with oil, water and gas meters, and automatic level and pressure controls. When the new testers were first introduced, they did not perform well and only one third of the tests were validated as “good” by Production Engineers. A multi-disciplinary team was set up and tasked with developing a work plan to solve problems with the new test separators in order to improve validation of well tests. The team addressed several issues including chemical injection, instrumentation, automation of well testing process, capture test data into software applications, trouble shoot wells, develop KPIs, and train operators.

As a result of the team's effort, well testing performance has significantly improved. Well test validation has increased from 30% to 90% and the number of daily well tests doubled from 32 to 64. With this improvement, the company was able to reduce the contracted well testing service and reduce cost. Additionally, through quality well testing, there was an improved understanding of individual wells performance, thus allowing better production optimization and reservoir management.
Combining Horizontal Production Logging and Distributed Temperature Interpretations to Diagnose Annular Flow in Slotted-Liner Completions
Authors: Haoua T. Ben , Abubakr S. , Pazzi J. , Djessas L. , Ali A. M. , Ayyad H.B. , Boumali A. , Boulkaila Z. , Brahim M.H.
Published: March 2015

Production logging in horizontal wells has been challenging due to phase stratification and complex flow regimes. New technologies were introduced to properly characterize such flow dynamics; however, adding a new complex completion strategy, such as a slotted liner, raises the challenge to a new level. When a slotted liner is not equipped with a hanger, two flow paths become possible—one inside the slotted liner and the other outside it—with possible fluid exchange between the two paths. Production logging tools can only see the inner flow. The lack of information about the outer flow raises uncertainties about the real producing zone(s) and may affect the success of future well intervention operations.

We describe a new methodology that combines multiphase production logging measurements with distributed temperature survey data. Both sets of data were acquired simultaneously during conveyance of the production logging tool on coiled tubing. The production logging data offers insights into phase distribution and enables production profiling inside the slotted liner; distributed temperature data solves for total formation production. Combining the two interpretations enables quantification of flow in each of the two paths and helps identify the fluid exchange between them, which would otherwise be misinterpreted as fluid entry from the formation. The result of this integrated interpretation methodology is accurate determination of zonal contributions.
Integration of Reservoir Performance and Geoscience Studies in the History Match of a Complex Carbonate Reservoir – a Case Study from the Magwa Marrat Reservoir - Kuwait
Authors: Jadi Menayer Al , Kumar Pranay , Lislaud Frederic , Robert Joël , Alessandroni Mauro , Lefebvre Christian , Groen Vincent de , Vigier Louise , Datta Kalyanbrata , Hafez Karam , Taneja Hans , Bhattacharya Muktibrata , Bond Deryck
Published: March 2015

An integrated reservoir study of the Magwa Marrat reservoir has been completed recently. This study was carried out to support the continued development of the reservoir, in particular the planning of a secondary water flood.

The initial part of the study concentrated on reservoir characterization and reservoir performance over a long period, in the order of 30 years, of primary recovery, followed by analysis of a recent pilot water flood. A better understanding of the controls of flow and the role of fracture corridors and diffuse fractures was achieved through and integration of geophysical, petrophysical and dynamic data including tracer tools and in particular through a dynamic model of the water flood pilot. The uncertainties related to structural extension, especially on the flanks of the field and related to aquifer support, were also recognized.

Later on static and dynamic models were built, first around the pilot water flood area and then for the entire reservoir. These models have been used for development planning.

This paper gives an overview of the integrated study but concentrates on the features, detailed below, that were key to better understanding the fluid flow physics and to achieve a satisfactory “history match”.

A single porosity model that accounted for matrix permeability, local enhancement to permeability within restricted fracture corridors and the effect of diffuse fractures in “tight” zones was adopted. Matrix permeability values were based on the results of a rock typing study. Static and dynamic pressure, oil production and water movement matching was achieved by making limited and realistic changes to fracture zone permeability, fracture zone extent and some fine tuning of matrix permeability. Well productivities, pressure transient tests, interference tests and production log data were used to guide and validate the history match.

Water-cut match was further improved by making reasonable changes to the structural model in regions where significant structural uncertainty was recognized.
BBS Implementation in the Middle Eastern Oil & Gas Environment -Moving Ahead
Authors: Al-Failakawi Ali , Al-Qallaf Yousef , Adivi Bala Siva
Published: March 2015

This paper describes one successful approach of Behavior Based Safety (BBS) implementation in Oil & Gas Company in Kuwait. The unique approach involved tailor made approach and implementation has been done through the very basic building blocks. Much emphasis was placed on understanding the Middle Eastern Social Culture, organizational culture including the HSE culture and then designing the BBS program to suit the cultural norms.

Several organizations in the Middle East Region have implemented in-house versions of Behavior Based Safety (BBS) programs such as STOP, ASA, SOC, and so on. However, these programs have been driven by Key Performance Indicators (KPI) and therefore suffered from number-crunching instead of focusing on quality execution and effectively influencing behaviors. Quite a few BBS consultants have attempted to implement their respective copyright BBS programs in this Region. There has been varying successes.
Gas Lift Optimization using Artificial Neural Network
Authors: Ranjan A. , Verma S. , Singh Y.
Published: March 2015

Due to the increasing number of brown fields and lessening of huge oil discoveries maximizing recoveries by artificial lift techniques can be a compensating factor to balance the demand to supply ratio. Gas lift holds a promising aspect in this regard especially for offshore platform where every square inch costs thousands of dollars and space is limited. Gas lift occupies very little space at the wellhead and many directional wells can be drilled close together and easily produced. Although gas lift optimization has been attempted using soft tools like fuzzy logic, pattern recognition and intelligent network, none of them holds promises as big as artificial neural network. The gas lift optimization considered in this paper is to maximize the daily hydrocarbon production by selecting optimally the lift gas rates. The procedure utilizes well test information and calculations of vertical two phase flow behaviour to predict field producing rate responses to changes in gas input rate. Nodal analyses, gas lift databases and gas lift monitoring system are among the tools applied to meet the objective by training and testing various ANN models by varying number of neurons in each layer, learning rate, training type, epoch and minimum error. It is confirmed that in comparison with the models previously published in literature our ANN model has a better accuracy and performance in optimizing the gas lift rate.
PICD Performance Evaluation Study for Carbonate Field Using Post Installation PLT and Production Data
Authors: Lee Byung , Galimzyanov Artyom , Faizal Syed Abu , Vicario Roberto
Published: March 2015

Passive Inflow Control Devices (PICD) are a common completion method for horizontal wells. A PICD completion can not only equalize the fluid influx along the length of the horizontal well but also can delay breakthrough of unwanted fluids and solve the challenges associated with uneven reservoir heterogeneities. Saudi Aramco is now the world leader in the use of PICD technology.

Since the first installation of PICD in 2002, Saudi Aramco utilized various types of PICD for their sandstone and carbonate oil fields. Among these fields, one particular carbonate field was selected to study the performance of PICD completion and assess its effectiveness over barefoot completion. Production logs from 22 post-installation horizontal wells with PICD from the subject were analyzed. A near-wellbore simulator was used to match the actual fluid influx in PICD completion obtained from production logs. The matched model was used to simulate the flux profile for the openhole case and well performance was compared with PICD case. As part of the evaluation, production history of the PICD installed wells was also studied. Time-to-water breakthrough and increase in water-cut trends for PICD-installed wells were investigated to find how PICD design can improve fluid flux along the horizontal well and delay unwanted fluid. This exsercise helped identify optimization design guidelines with regards to number of compartments, PICDs per compartment and the process of dealing with uncertain changing well conditions in naturally fractured carbonate field. Dynamic modeling was also performed to evaluate the suggested PICD design recommendations with respect cumulative oil production and water breakthrough deferment.

This paper describes the detailed evaluation methodology, analysis results for the selected field and subsequent recommendations for design practice to maximize the value of PICD.
Successful Implementation of CO2 Energized Acid Fracturing Treatment in Deep, Tight and Sour Carbonate Gas Reservoir in Saudi Arabia that Reduced Fresh Water Consumption and Enhanced Well Performance
Authors: Malik Ataur R. , Dashash Alaa A. , Driweesh Saad M. , Noaman Yousef M. , Soriano Eduardo , Lopez Alfredo
Published: March 2015

Up to three thousand barrels of stimulation fluids are pumped during a single vertical fracture treatment in carbonate reservoir of Saudi Arabia with the objective of creating sufficient conductive reservoir contact for commercial production. The post-stimulation production performance in deep, tight, and sour carbonate gas reservoirs often does not meet expectations due to complex reservoir characterization and poor transmissibility. The post-stimulation cleanup period often takes much longer due to resistance in unloading the pumped fluids.

Carbon dioxide (CO2) with 30% foam quality (FQ) has been introduced for the first time during acid fracturing treatment in the tight, sour and high pressure, high temperature (HPHT) carbonate gas reservoir of Saudi Arabia to reduce consumption of fresh water, minimize reservoir damage, reduce the flowback period and eliminate the need for nitrogen lifting with coiled tubing (CT). The water and acid volume were reduced by one third through energizing the fluids system with CO2 during acid fracturing treatment in the candidate well. The Pad fluid was a zirconate crosslinked gel that was optimized for low pH to maintain stability in the presence of CO2. To minimize fluid leak-off and improve diversion effects, a chemical diverting system was included in the CO2 energized acid fracture treatment. A non-emulsifier foaming agent was used in the Pad and acid blends to create the desired emulsion with CO2. The post-fracture flowback period was reduced significantly and a 2.5 fold increase in the gas rate was realized.

The addition of liquid CO2 to HCl in quantities sufficient to produce emulsion allows live acid to retard and penetrate much deeper than HCl itself. The CO2 strips hydrocarbon from the rock and allows acid to effectively react to the rock surface. CO2 remains in the liquid or supercritical phase during injection mode and flows back in the gas phase over a wide range of temperature and pressure allowing pumped fluids to recover in fast and safe manner.

This paper is focused on laboratory tests of fluid systems, and the design, execution and evaluation of CO2 energized acid fracturing treatment, and a safe flowback strategy used for sour wells with high a concentration of CO2.
Coiled Tubing Conveyed Video Camera and Multi-Arm Caliper Liner Damage Diagnostics Post Plug and Perf Frac
Authors: Ashby S , Al-Shamrani S , Hansen J , Almutairi T , Al-Mulhim A
Published: March 2015

This paper describes the experiences of utilizing coiled tubing and its conveyed diagnostic tools, following a multi-stage plug and perf acid fracturing treatment performed in a highly deviated well. A downhole video camera and multi-arm caliper run on coiled tubing were used for the first time in Saudi Aramco gas wells.

The well is a gas producing well in a thick carbonate structure and was drilled at a high angle to intersect several different porosity layers within the formation. The well was also drilled at 30 degrees to the minimum stress direction to allow the creation of transverse fractures from each frac stage. The final completion consisted of five frac stages spaced out along the interval separated by four bridge plugs. Following the completion of the fracturing operations the initial attempt to mill the plugs was unsuccessful as the milling tools were unable to reach the depth of the first plug. At this stage the well was potentially lost due to suspected damage or deformation to the liner caused during the fracturing.

A series of diagnostic runs was performed with coiled tubing and a milling strategy formed from the results. The diagnostics included first time use in the area gas wells of a downhole video camera and multi-arm caliper conveyed on coiled tubing.

The diagnostics were successfully completed and analyzed. From these results the required milling tool diameter was determined and a milling bottom-hole assembly was designed. Coiled tubing was re-mobilized and the plugs were successfully removed from the liner allowing full bore access and the well to be flowed back.
Effect of Sand Deposition in a Riser: Case Study of the Jubilee Field Riser
Authors: Anthony William , Owusu Mark
Published: March 2015

Sand production is a common phenomenon in hydrocarbon extraction. It is the migration of formation sand as reservoir fluid flows, and can accumulate downhole around the production interval thereby blocking the production interval, and hence reducing production rate.

The Jubilee Field experienced sand production during its early production stages. Although the challenge has been addressed through acidising, however, sand production is inevitable as the field matures. It is always desirable to have these sands flow through the riser to the surface. The flow conditions, the sand flow dynamics and the riser bathymetry could lead to sand deposition and accumulation in the riser. This study examines the flow dynamics and the effect of sand deposition on the flow integrity in a typical riser using computational fluid dynamics. It uses the Jubilee Field East Loop riser as a case study.

It has been deduced that for the given flow conditions, there is the possibility of sand deposition and/or accumulation in some sections of the riser, and that low points in riser bathymetry are possible sources of onset for sand deposition. Sand dispersion decreases from the point of injection towards the lower region of the flow domain downstream from the injection point. Flow pressure and velocity were significantly affected by sand deposition and/or accumulation within the flow domain especially areas in the proximity of low points. The study established that uncontrolled deposition and/or accumulation of sand within these sections of the flow have the possibility of changing the flow characteristics within the riser.

This study would aid in proposing effective strategies to mitigate the impacts of sand deposition in a riser. It will contribute significantly to the implementation of an effective pressure and sand management strategy.
Revelation of the Triassic Gas Potential with Insight of Iso Frequency Spectral Decomposition in Saudi Arabia's Offshore
Authors: Sodagar Taher M.
Published: March 2015

Two fields in the eastern offshore of Saudi Arabia were evaluated for the feasibility of an Iso Frequency Spectral Decomposition (FSD) approach to recognize the hydrocarbon presence in two key Triassic reservoirs – Minjur and Jilh formations. Another essential objective was the integration of an advanced Iso FSD technique with other traditional seismic attributes, to identify new possible hydrocarbon sweet spots at the same reservoirs, as well as new potential Triassic plays in the study area. Wells in the first field have hydrocarbons in logs and from tests in the Triassic reservoirs, while a well in the second field shows no hydrocarbon of any kind. 3D seismic data was used to create acoustic impedance inversion and FSD data volumes. Gas bearing reservoirs typically diminished more rapidly at the high frequencies than wet reservoirs. Incremental FSD volumes from 5 to 40 Hz were generated to identify gas saturated locations. Reservoir maps were also produced for seismic amplitude, inversion and FSD attributes.

The frequency maps for the Triassic aged formations demonstrated sweet spots at the first field and dimmed at the second field at 10 Hz, while diminishing rapidly at these sweet spots on higher frequency maps. The inversion map for the Minjur Formation displayed low impedance at both fields. The inversion map for the Jilh Dolomite reservoir exhibited low impedance at the first field and high impedance at the second field. The inversion map for the Lower Jilh (a new play) showed relatively high impedance at the first field and fairly low impedance at the second field. The FSD and inversion maps consistently agreed with the offshore Triassic wells for gas detection and porosity. The seismic attribute maps integrated with Iso FSD maps led to identifying potential drill locations with good porosity and gas detection within Triassic formations in Saudi Arabia's offshore field areas.
Case Study: Promoting an Effective HSE Culture in a Young Joint Venture with a Massive Operation to Rejuvenate a Mature Field
Authors: Hussain T. , AlJamea D.
Published: March 2015

Discovered in 1932, the Bahrain field is one of the oldest oil fields in the Middle East. In 2009, a new Joint Venture company comprised of international oil companies was created, Tatweer Petroleum, with the objective to rejuvenate the mature Bahrain field reservoirs.

Tatweer Petroleum immediately embarked on a massive field-wide development plan managed by an army of 800 employees and more than 5,000 contractors. The vigorous operation involved parallel execution of major infrastructure projects to accommodate new production from 650 new wells (drilled in 4 years) that included debottlenecking of existing facilities, a new power distribution system, tank batteries, well manifolds, gas compression, gas dehydration, water treatment plants, and steam generation plants, as well as several environmental, health and safety improvement projects.

The magnitude and pace of the redevelopment activities posed a continuous challenge on the Health, Safety and Environment (HSE) team who had to ensure compliance with local and international HSE standards and meet tight company KPIs and HSE targets.

Leveraging valuable, rich experience and safety cultures of its international partners, Tatweer Petroleum effectively launched several HSE initiatives that significantly improved the HSE performance of the operations.

This paper presents how Tatweer Petroleum managed to achieve high HSE standards through the implementation of a series of aggressive campaigns and programs side-by-side with the massive operation citing three examples of these HSE initiatives.
Large-Scale Physical Simulation Experiment Research for Hydraulic Fracturing in Shale
Authors: Wang Yonghui , Fu Haifeng , Liang Tiancheng , Wang Xin , Liu Yunzhi , Peng Yi , Yang Lifeng , Tian Zhuhong
Published: March 2015

Successful development of shale gas in North America triggered great enthusiasm of developing shale gas in China. Experiments for hydraulic fracturing shale Outcrops sample in 762×762×914mm(height) were performed by using large-scale true tri-axial testing system to study what kind of hydraulic fracture will be for South China marine shale and how the formation condition or the human-controllable parameter influence the fracture complexity. Investigations of fracture geometry and fracture complexity are conducted with different natural fracture distribution, different main stress difference, different fracturing fluid viscosity, different injection rate, using methods such as acoustic emission monitoring and cutting the rock sample into pieces. The testing results show the hydraulic fracturing in shale generates more complex fractures than that of in sandstone, where both tensile and shear cracks are observed. Natural fractures, shale bedding and small principal stress differences are in helping to form complex fractures. When a low viscosity fluid is used, complex fractures are easier achieved than that with high viscosity fluid. This work explores a way of conducting hydraulic fracturing large-scale shale test. The testing results provide important basis for numerical simulation of fracture propagation, pre-frac layer or stage choosing and fracturing design optimization for hydraulic fracturing in shale.
Case Study: Design, Execution and Results of Retrieving Challenged Gravel Packs, the Future in Workovers
Authors: Gonzalez Luis D. , Costeno Hugo , Djohor Mohamed , Curteis Charles , Raziyev Mukhamed , Rivero Maria
Published: March 2015

Workover is the process of performing major maintenance or remedial treatments on an oil or gas well to restore, prolong or enhance its production. The complexity of workover operations is increasing due to the well conditions faced, such as age, environment, mechanical restrictions, completion design, number of completed zones, downhole equipment installed, etc.

Well workover can represent up to 49% cost reduction over its sidetrack option, making it economical; but it may require good sand control understanding, and comprehensive procedures, to retrieve existing gravel pack (GP) assemblies, an operation that possess the risk of getting stuck and/or being unable to retrieve the assembly and eventually abandoning the well. For many years the Oil Industry has rejected workover candidates because of risk aversion overriding cost and value added; the actual workover opportunities include new challenges such as retrieving Alternate Path screens.

This paper discusses the design, risk management approach and the challenges faced during execution, as well as the lessons learnt, of two workover wells in a brown field; both candidates had several challenges such as: Old completion,Lack of reference data,Length of screens (500 ft of screens)Sand productionDifferences to retrieve Wire Wrap and Alternate Path screens

The two successful retrieval of the sandface completion in both wells were the first and second operation of its kind performed by the operator and provide field experience and best practices for future similar operations. Furthermore; the study of the retrieved assembly, after over 20 years of production, helped to understand the sand management system failure mode and the reasons for the sand production issue; knowledge that will impact future well designs in the field.