bluuebunny/crossref_metadata_2025 huggingface dataset:
Processing Formation Test Data to Reduce the Risk Inherent in Capturing Representative Samples in Zones with Highly Varying Permeabilities
Authors: Deering James , Mohsin Mustafa Abdul , Proett Mark , Eyuboglu Sami , Fakhry Waleed
Published: June 2015

A new method of objectively quantifying formation tester data quality has recently been developed with the aim of optimizing the generation of fluid gradients and contacts. This paper demonstrates how this new method of processing formation test data and integration with the open hole log data can be applied to improve job planning for sampling. By using data that have been quality controlled, sampling operations can be improved by using the optimal sampling tool configuration which can result in higher operational efficiencies with reduced rig time for complex logging and sampling operations. In this case study, formation tester objectives included establishing gradients and fluid contact points, determination of formation fluids and capturing representative samples over multiple horizons in a single 6 ⅛" wellbore. An additional factor which increased the complexity of this operation was the length and deviation of the wellbore, raising concerns about differential sticking due to the lengthy stationary sampling times required. The formation tester evaluation process was divided into two runs: wireline deployed pressure testing and drill pipe conveyed sampling. This culminated in successfully completing 22 pumpouts with 4 samples captured over 6 days without any incidents. The straddle packer was used 17 times in varying permeability formations and is considered to be the most number of inflations in the Middle East region.

The real-time formation tester data acquired were compared to the quality controlled data used for post processing analysis. The results were then used to identify the optimum procedures to be followed and future best practices. The lessons learned from the case study presented are used to demonstrate a quality control process with recently developed realtime methods for evaluating test quality. This allowed the data to be analyzed quickly and with confidence, enabling improved pumpout and sampling operation planning.
Overcoming Formation Evaluation Challenges in Short Radius Re-entry Wells in Aging Reservoirs
Authors: Ageel Ibraheem M , Baikelov Chingiz , Sanchez Pablo , Hameed Aamir , Gupta Sunil , Ammar Karim , Al-Momen Osamah
Published: June 2015

Innovations in drilling and completion technology has opened a new era in the oil and gas sector revitalizing old fields either to tap bypassed pockets of hydrocarbons or enhance the recovery factor with re-entry wells. Now enhancing production from aging fields has become a major activity for oil and gas companies. However, this is not a straight-forward decision and often the oil companies are challenged with the casing integrity, inadequate or missing log data and being able to complete the well economically.

The history of re-entry wells goes back to 1950's but it is only recently that the industry is seeing more medium and short radius wells to improve operational efficiency and to make the projects more economical. Slim borehole, complex geometry and high dogleg severity are the common attributes of such re-entry wells. Unequivocally, these complex wellbore geometries will improve recovery of reserves and maximise the net present value (NPV); however the real challenge lies with the acquisition of formation evaluation data. In these challenging conditions conventional Wireline or LWD techniques cannot provide adequate solutions to obtain much needed formation evaluation data. It was one of the reasons why most of the challenging re-entry wells in the past were not logged. Saudi Aramco faced similar challenges in one of their re-entry aging wells. The well was drilled in 1968 as a vertical open-hole producer. A series of work-overs were performed over the life of the well and in 2002, the well was side-tracked and a short radius trajectory was chosen to drill a horizontal section. During drilling the operator encountered a total loss circulation zone and was forced to plug the zone blindly without being able to log and investigate the cause.

Memory logging and slim tools have been introduced in the last decade. The operator planned to carry out another work-over in 2014.
Enhancing Drilling Operations in SHYB Oil Field by Relating Drilling Azimuth to Formation Geomechanics: A Field Wide Case Study
Authors: Al-Rabeh Majed , Abu Ahmad Yousif , Ramirez Ivan
Published: June 2015

The Shaybah oil field (SHYB) is located in the southeast area of Saudi Arabia and it's where Saudi Aramco drills the most complex multilateral wells and runs the most advanced intelligent well completions. The target reservoir is the "Shuaiba," which is an extensively drilled carbonate reservoir. Also, the geomechanics and overall stresses of the Shuaiba were characterized back in 2001 in a study, which concluded that the maximum horizontal stress orientation in SHYB appeared to be north - south and that the magnitude of this stress is only slightly greater than, or equal to, the minimum horizontal stress making up what is known as a normal faulting stress state (Geomechanics International)2. Consequently, due to the limited amount of data that was available back in 2001, the conclusions regarding stress orientation would need to be confirmed as additional data becomes available. And nowadays, after 14 years of development, a larger set of data has become available.

Therefore, the purpose of this paper is to supplement the results of the previous geomechanical study performed in 2001 using recent drilling data from 100 wells drilled after the previous geomechanical study was conducted. In other words, this paper uses the findings of recent hole stability data from 100 wells to confirm the earlier suggested normal faulting stress state. And based on the findings of this analyses, there was no strong evidence to suggest that the hole becomes significantly more stable when drilling along the maximum horizontal stress direction (N-S) or conversely, becomes significantly less stable when drilling in any other direction, especially in the minimum horizontal stress direction (E-W). This finding confirms the normal faulting stress in SHYB and that hole stability does not vary greatly with drilling azimuth for this specific field.

Most of the last 100 wells drilled in SHYB were drilled along the NE - SW directions of the field. And from 84 wells drilled along the NE - SW directions, only six wells experienced hole instability. Also, out of 11 wells drilled in the N or S direction, which is the maximum horizontal stress direction, no hole stability issues were recorded. Out of the seven wells drilled in the E or W direction, which is the minimum horizontal stress direction, only one well experienced hole instability. Therefore, the findings of the analysis show that there is no strong evidence to indicate that significant hole stability improvement is achieved by drilling in the maximum horizontal stress direction.

In conclusion, this paper discusses the results of a field wide case study performed using the drilling data of the last 100 wells drilled in SHYB. The available data seems to confirm the normal faulting stress state that was earlier suggested for the SHYB field. With this confirmation of stress orientation, the expectations for hole stability are improved and this reflects positively on well planning and overall field development.
Innovative Coiled-Tubing Deployed Zonal Isolation of a Highly Permeable, Acid-Fractured Carbonate Reservoir in Saudi Arabia
Authors: Gill Harmohan , Morris Ronald , Karadkar Prasad , Danish Syed , Arenas Angel , Deonarine Keshan
Published: June 2015

This paper highlights the difficulties and limitations faced along with the respective solutions proposed and executed during the zonal isolation of a highly permeable, naturally fractured and acidized carbonate reservoir during its exploration phase after having performed an extended pressure buildup (PBU) test on a remote field in Saudi Arabia.

To accurately compute the hydrocarbon reserves of a particular region, operators must explore new reservoirs in remote areas, in both challenging offshore and onshore environments, to decide future field development. The services performed on these wells include drill-stem test (DST) completions, underbalance perforation, acid stimulation, placing downhole gauges/shut-in tools, extended flowback and PBU periods, and final zonal isolation.

In this candidate well, the operator wanted to test three zones, further performing high-rate acid fractures on the lower two zones to be able to determine commercial hydrocarbon gas rates. The first major challenge was for zonal isolation of the lowest zone, expected to be a highly fractured zone that might also be stimulated. A cement plug was designed to be deployed by means of coiled tubing (CT) for accurate placement and depth control. The added challenge in this exploratory well was to plug any wellbore channels and highly permeable fractured streaks in the lowest reservoir zone after acid stimulation and reservoir evaluation were completed while preventing excessive cement fluid loss into the zone from the cement volume that would challenge the plug effectiveness. This paper explains the innovative solution devised for this well, including the job execution and elaborating on the combination of CT intervention, carefully designed chemical blends, cement fluid handling systems, and implementation of best practices to deliver a successful zonal abandonment. The operation consisted of three runs: the first used a lead batch of an organically crosslinked polymer with loss circulation material (LCM) in the solution; the second was performed for cleanout, displacement, and permanent cement slurry placement; and, after waiting on cement (WOC), the third was used to tag the top of cement (TOC) and perform a pressure test. The organically crosslinked polymer with LCM solids served to bridge off the perforation tunnels and potential fractures in the rock so that a precise volume of cement plug slurry could be pumped safely and accurately.
Formation Pressure Estimation and Miocene Clay Minerals Assemblages Identification, Drilling Challenges and Mitigation, Integrated Case Study, Gulf of Suez, Egypt
Authors: Abdallah Khalid , El Sherbeny Wael , Darwish M. , El Kammar M. , Gouda Mohamad , Al Shaikh Nasser Sadiq A. , Al-Hakim Mohammad
Published: June 2015

The pressure regime modeling is an integral part of the well planning and formation evaluation process. An adequate prediction of the estimated pore pressure and better understanding for the pressure regime of any area are important prior drilling any well to optimize the proposed wells target location and enable the well planner to anticipate the location and the potential magnitude of the possible abnormal pressure problems for future drilling plans and consequently minimizing drilling cost.

Wellbore instability, particularly in shale formations, is a major challenge in drilling operations. Many factors such as rock properties, in-situ stresses, chemical interactions between shale and drilling fluids, and thermal effects must be taken into consideration in well trajectory designs and drilling fluid formulations to mitigate wellbore instability-related problems.

Energy dispersive X-ray analysis (EDAX) is a technique used for identifying the elemental composition of a specimen. The EDAX analysis system works as an integrated feature of a scanning electron microscope (SEM).

Identifying shales by X-ray diffraction (XRD) operates on the principle that all minerals and clays are poorly crystalline, exhibit less sharp peaks, because of weathering effects and the substitution of ions at the atomic level crystalline (to some degree)., In contrast Quartz is highly crystalline and with XRD, produces a narrow, sharp peak.,

The paper indicates the degree of integration utilizing both pore pressure data and clay mineralogy to minimizes the uncertainty to properly anticipate drilling challenges and drilling fluids design, in additions it will reveal all XRD and SEM results that define the clay mineralogy and chemistry for Miocene succession in addition to drilling challenges related to each type of clay (bit balling, fine migrates, caved shales and difficulties running the BHA string). The paper will also provide recommendations for drilling fluid design to mitigate drilling challenges and minimize reservoir damage.

Integrating both pore pressure estimation and clay mineralogy determination for specific troublesome formation can minimizes uncertainty for anticipated drilling challenge and proposed solutions.
Chemical Enhanced Oil Recovery Pilot Design for Heglig Main Field-Sudan
Authors: Ali Husham A. , Musa Tagwa Ahmed , Doroudi Abe
Published: June 2015

Chemical flooding is known as one of the Enhanced Oil Recovery (cEOR) methodology to increase recoverable oil from the aging reservoirs, so that: several successful chemical injection projects were done worldwide for the past decade.

Previous studies in screening of EOR methods for the Sudanese oil fields show that Heglig Main oil field is suitable candidate for cEOR operation; the Stock Tank Original Oil in Place (STOOIP) for this field is about 577.95 MMSTB where only 22.2 % was produced through naturally depletion.

The objective of this research is to select the optimum pilot area and to design the cEOR pilot in Heglig Main oil field through a dynamic simulation modeling study; this model was constructed and run in advanced Thermal/Chemical simulation software. The scope of work of the pilot study is; a) to ascertain the alteration in oil saturation, injectivity, chemical absorption, and chemical breakthrough time for cEOR in this field, and b) to obtain pilot results in order to further refine to the cEOR full-field model.

The advantage of pilot model study is; reducing the cost by utilizations of existing wells and also minimizing the operating constraints by selecting the poor/medium performing wells.

According to the current study, a sector model with the well spacing of 200-350 m which is main factor for choosing the "pilot well area" could be properly implemented to check the flooding behavior, continuity, predict the production performance and incremental oil recovery, as well as to predict cEOR response and breakthrough time.

In this paper, pilot area as a sector model extracted from Heglig main field and a dynamic simulation model was constructed. Accordingly, seven (7) scenarios of 5-spot pattern were prepared and run in advanced Thermal/Chemical simulation software. Sensitivity analysis and optimization were also done to achieve the best scenario of the chemical flooding.

The results show that a combination of 0.4wt% of Alkaline, 0.1wt% of Surfactant, and 0.1wt% of Polymer in an ASP flooding process can increase the recovery factor of Heglig main up to 43.54%.
A Market Survey of Offshore Underwater Robotic Inspection Technologies for the Oil and Gas Industry
Authors: Ledezma F. Diaz , Amer A. , Abdellatif F. , Outa A. , Trigui H. , Patel S. , Binyahib R.
Published: June 2015

This paper is aimed at providing an insight in some of the most up-to-date technologies for offshore pipeline inspection. The first part reviews the basics of the main underwater pipeline inspection technologies that are commonly used to detect signs of corrosion, fractures and other flaws. The second part surveys the existing robotic technologies for deep and shallow waters that are dedicated to underwater monitoring and inspection of pipeline integrity.
Magnetic Flux Leakage (MFL) Technology Provides The Industry's Most Precise Pipe Integrity And Corrosion Evaluation, Accurately Characterizing Casing And Tubing Strength. Technology Overview And Case History
Authors: El Sherbeny Wael , Nuic Ivo , Hasan Gasser , Abdesslam Abba , Hassane Tharwat
Published: June 2015

The Magnetic Flux Leakage (MFL) Technique is the most commonly used technique to inspect large diameter transmission pipelines. A typical MFL inspection system uses permanent magnets to apply an axially oriented magnetic field to the ferromagnetic pipe material. The magnetic field is perturbed by a metal-loss region (usually caused by corrosion) to produce flux leakage outside the pipe, which can be measured by field sensors.

The magnetization system in an MFL inspection system should ideally produce a magnetic field that is strong enough to cause a measurable amount of magnetic flux to leak from the pipe material at metal-loss regions, uniform from inside to the outside surface of the wall thickness so that the measured signal is more linearly related to metal-loss depth, and consistent in magnitude along the length of a pipe so that flux leakage measurements can be compared at different locations during an inspection run.

In general, the field strength most strongly affects detection of metal loss defects while characterization of defect geometry requires a field that is strong, uniform, and consistent.

Improvements in the downhole hardware also provide more flexible and efficient data acquisition, reducing operating time while improving data accuracy and operational safety. In conventional magnetic flux leakage (MFL) tools, the flux leakage sensors are coils; in the "high-resolution" tool, the coil is replaced by multiple "Hall Effect" sensors.

The HR Vertilog service uses MFL measurements to identify and quantify internal and external corrosion defects. The overlapping arrays of flux-leakage sensors and discriminator sensors offer full circumferential inspection of the tubing or casing string. This process differentiates between metal-loss (corrosion) and metal-gain (hardware) Features, and distinguishes between general corrosion and isolated pitting. Paper represents technology overview and field cases history
First Autonomous ICD Installation in Saudi Arabia-Modeling a Field Case
Authors: Al-Kadem Mohammad , AlMuhaish AbduRazzaq , Lee Byung O , Least Brandon
Published: June 2015

Maximizing oil production in horizontal wells is the most critical factor to enhance oil recovery for reservoir management purposes. Technologies in oil industry have been improved dramatically starting the horizontal wells to Extreme reservoir contact wells. However, this drastic improvement has been challenged when water or gas invades the reservoir. Conventional passive Inflow Control Device (ICD) is very excellent technology which primarily aims to balance oil influx over the entire reservoir and hence increase the oil recovery. However, there are several types of ICD in which they work based on viscosity factor. For instance, conventional nozzle type can operate with the reservoir fluids at different viscosities however in contrast, the other type i.e. Helical or channel ICD is dependent on viscosity. Both mentioned types can be functioned properly at early stage of the well production life however problems are encountered when there is water or gas breakthrough. A new generation of ICD is the Autonomous Inflow Control Device. This new type of ICD has the ability to proactively provide additional restriction on undesirable fluids based on viscosity and mobility. It can be operated at different viscosity ranges which confirmed its applicability in any type of reservoirs.

It is good to mention this AICD is going to be tested and evaluated for the first time on three wells in Saudi Aramco. One of the wells is going to be discussed in this paper with the following aspects:

The selection factors for installing AICD on the subject well based on reservoir and field data. Historical production of the well along with major events in terms of water coning issues. Pre-modeling of the AICD completion using NETool™ simulation software. Comparison between Standalone Screens (SAS) and AICD using the NETool™. Verification of field results with NETool™ modeling.

This paper describes the added values of installing AICD technology over the conventional type in heavy oil reservoir in which it maximizes oil production, enhances oil recovery and more importantly delay the water or gas breakthrough with more restriction. This will be thoroughly discussed with the use of the simulation results.
Innovational Techniques in Utilizing Real-Time Downhole Pressure and Distributed Temperature Surveying for Skin Quantification During Matrix Stimulation in Complex Multilateral Well in Saudi Arabia
Authors: Bokhari Noordeen , Ghamdi Talal , Ahmed Ramy , Al-Dosary Abdulrahman
Published: June 2015

This paper describes an innovative workflow for well intervention in a complex multilateral well, not only for accessing each lateral, but also to quantitatively evaluate matrix treatment in real-time for each lateral independently. The quantitative evaluation is based on two simultaneous criterions. The first is derived from the downhole pressure diagnostic plot (pressure transient analysis) in real time using the data acquired by the downhole real time gauge. The second is an estimate of the zonal coverage from the temperature profile plot before, while, and after pumping a treatment. Pressure transient analysis gives the skin as a direct output, and the cooling down/warming up distributed temperature sensing profiles identify where the treatment fluids went into the formation.

This approach of combining well testing analysis techniques throughout the treatment in combination with zone coverage evaluation is strongly recommended for horizontal and complex wells, either clastic or non-clastic rocks. Basically, deriving the skin from the injectivity test (pre-treatment) and the skin from the post flush (post-treatment) will give an accurate as well as confident result when evaluating matrix treatments.

In a field case, a comparison of the formation damage skin before and after the treatment was performed on the spot, and an improvement of eight times in injectivity was achieved with nearly uniform distribution of treatment fluids across five well laterals.

Following the state-of-the-art procedures proposed and executed in this well, we were able to combine different technologies and techniques, which provided measurable cost reduction. The application of the technique will lead to eliminating confusion in accessing well laterals, quantifying the formation damage improvement in real time, eliminating the non-uniform distribution of treatment, optimizing diversion design/placement, and the ability to make treatment changes on the spot.
Use of Wellhead Data for Pressure Transient Analysis for HPHT Gas Wells
Authors: Kabir Akim , Saavedra Sebastian L. , Utaibi Abdullah , Basri Mustafa
Published: June 2015

The idea of using wellhead data for pressure transient analysis is very attractive, as if it is successful it spares us from the need to deploy any type of downhole tools, which are costly and wireline conveyed tools pose various mechanical risks including planting fish in the wellbore. The economics is overwhelmingly in favour for deep and hot wells where wireline intervention costs are high and workovers are expensive. Wellbore storage, presence of a second phase, cooling of the fluid column are some of the major obstacles in making use of wellhead data for pressure transient analysis.

In this paper we describe our experience of Pressure Transient Analysis using wellhead data for some dry gas fields in Saudi Arabia. For most of the cases wellbore storage is not an issue, as we can design the test for a period long enough to get out of that region. We have conducted some pressure build-up tests with gauges at both downhole and wellhead. Then we have converted wellhead pressure (WHP) data to bottomhole pressures (BHP) using the popular Cullender-Smith method and its various modifications. Two phase region and wellbore storage effect have been overcome. However, temperature transient has been found to be the biggest challenge which affects not only the absolute BHP, but also the bottomhole pressure trend which forms the very basis of transient pressure analysis. A thermal decay function was used to model the temperature transient using the initial and final temperature profiles. The resulting calculated BHP trend gets closer to the actual measured data, however differences still remain. Then we spell out a detailed plan to mitigate the remaining uncertainties to make the best use of these wellhead pressure data and obviate the need for running wireline gauges.
Harnessing the Power of Type-2 Fuzzy Logic System in the Prediction of Reservoir Properties
Authors: Olatunji S. O. , Selamat Ali , Abdul Azeez Abdur Raheem
Published: June 2015

The unique power of type-2 fuzzy logic system is harnessed in this work by way of using it to improve the prediction accuracy of permeability and PVT properties in a hybrid intelligent model setting. In this proposed setup, hybridization of type-2 FLS (T2) and sensitivity based linear learning method (SBLLM) is presented and have been shown to considerably achieved improved performance over the constituent models, particularly the SBLLM. SBLLM, as a learning tool, have gained popularity due to its unique characteristics and performance. However, the generalization capability of SBLLM and other neural network based solutions often depend, to a large extent on the characteristics of the dataset, particularly on whether uncertainty is present in the dataset or not. The celebrated unique ability of type-2 fuzzy logic system in modeling uncertainties cannot be overemphasized. In this work, a hybrid system through the combination of type-2 fuzzy logic systems (type-2 FLS) and SBLLM is established, and then use to predict both permeability and PVT properties, which are very germane to the field of reservoir engineering and management; type-2 FLS has been chosen to be a precursor to SBLLM in order to harness the power of type-2 FLS thereby facilitating a means to better handle uncertainties existing in datasets. The dataset first pass through the type-2 FLS for possible uncertainty handling and prediction and then the output from the type-2 FLS is then passed to the SBLLM for its training and testing and then final prediction is done using the unseen testing dataset. Simulations have been carried out, using the built hybrid model, on different industrial datasets, for permeability and PVT properties separately. Results from empirical studies show that the proposed enhanced hybrid system performed better than each of the constituent parts, though the improvement made over that of SBLLM performance is higher compared to that of type-2 FLS, possibly because type-2 FLS is originally adept at modeling uncertainties. Thus it has been established here the huge benefit that could accrue from properly harnessing the power of type-2 fuzzy logic system.
PVT Characterization of a Wet Gas Reservoir and its Impact on Reserves Estimate
Authors: Al Marri Hamad , Kabir Akim
Published: June 2015

Wet gas reservoirs with very low Condensate Gas Ratio (CGR) are very simple hydrocarbon system to deal with. However, accurate reserves calculation requires an accurate knowledge of gas compressibility factor (z) at reservoir Pressure and Temperature. In the absence of laboratory PVT data, very often correlations are used to estimate Bg (formation volume factor) for these reservoirs. Then accuracy of those estimates remains a question which may have significant impact in the Gas Initial in Place (GIIP) calculation.

In this paper we review our experience in estimating and validating Bg for a wet gas reservoir system. Wellhead samples were taken from exploration, delineation and then development wells. Initial GIIP was calculated from Bg estimated using a popular Standing-Katz correlation. Then more rigorous equation of states (EOS) were used to compare the values against those derived through z-factor correlations. Peng-Robinson and Soave-Redlich-Kwong (SRK) EOS based estimates were about 8% apart. A laboratory PVT study was carried out to accurately measure formation volume factor at various pressure and temperature including the reservoir P and T. Results showed that Peng-Robinson EOS over estimates Bg by 1%, while Standing-Katz z-factor correlation and SRK EOS underestimate this by 3% and 7% respectively. The use of detailed PVT data for Reservoir Engineering calculations provides more accurate GIIP, 3% higher than the simple compressibility factor based gas equation of state in this case.
Comprehensive Reservoir Vertical Interference Testing to Optimize Horizontal Well Placement Strategy in a Giant Carbonate Field
Authors: Al-Harthi Mabkhout A. , Pardo Cesar , Kilany Khalid , Al Otaibi Majid , Zeybek Murat , Amin Asif
Published: June 2015

This paper discusses the early evaluation of vertical connectivity with vertical interference tests (VITs) using an advanced multi-probe wireline formation tester in a giant carbonate field in Saudi Arabia. The objective was to determine the vertical permeability of low permeability layers within the reservoir. Early understanding of the vertical connectivity is required to ensure the optimum development for new fields with limited dynamic data.

To conduct the evaluation, a multi-probe advanced formation tester was utilized in five key wells around the field to obtain vertical and horizontal permeabilities with several VITs creating pressure pulses at the dual packer, which produce pressure responses monitored at the two observation probes in real time. The vertical connectivity was assessed from the pressure response to the transient generated across stratigraphic layers. Comprehensive interference tests were conducted across all the layers. Advanced nonlinear regression analysis techniques were utilized for pressure transient analysis at test intervals. The results were further confirmed with a fine gridded 3D reservoir simulator. The integration of all vertical permeability results obtained so far indicated a good degree of reservoir vertical connectivity.

The VIT results were used as input in the field simulation model improving the accuracy of the vertical permeability in different areas of the reservoir, which in turn supported changes in the well placement strategy to maximize recovery.
Fracturing a Tight Sand Formation with High Frac Gradient Onshore Saudi: Challenges and Solutions
Authors: Al-Momin Ali , AlSaihati Ali , AlHamed Khalid , Rabines Jaime
Published: June 2015

Saudi Aramco has recently embarked on an exploration program targeting unconventional gas reservoirs to meet the ever increasing local gas demand. One of the targets is a tight sandstone play located to the east of a giant hydrocarbon reservoir with limited reservoir data through the few exploratory wells drilled in that play. The target formation is considered a deep reservoir with very low permeability and high fracture gradient. In order to evaluate the potential of the subject formation, wells have to be completed with a hydraulic fracture. Given the challenging nature of the reservoir in terms of stress, pressure and temperature, a sophisticated design of both well completion and fracturing treatment must be performed to successfully evaluate the potential of those wells.

This paper highlights all the challenges encountered and overcome from completing to fracture stimulating one of the wells in the target tight sandstone formation. Among the challenges is dealing with the completion limitation in terms of the maximum allowable pressure during the fracturing operations. Detailed simulations of the stress and thermal conditions mimicking the fracturing treatment have been analyzed to maintain the integrity of the well during the stimulation operations. Another challenge is the high fracture gradient and high closure pressure which resulted in limiting the injection rate to place the proppant. A cost effective fracture fluid formulation has been adopted to be able to frac and place the proppant without exceeding the tubing maximum allowable injection pressure. The fluid used was a linear gelled fluid system consisting of heavy brine which was selected after extensive laboratory testing. Acid spearhead along with sand slug was also employed to overcome the high NWB (Near Wellbore) friction and the proppant was placed successfully.

This paper presents a step-by-step design process which could be applied by other engineers to help in placing proppant into challenging formations with similar attributes of the subject formation.
First Fractured Horizontal Well with Offset Horizontal Microseismic in KSA
Authors: Kurdi Mohammed , Bartko Kirk , Alfataierge Ahmed , Alghamdi Fahad
Published: June 2015

With Saudi Aramco's recent ambitious endeavors toward exploring unconventional resources in the Kingdom, the Unconventional Resources Program at Saudi Aramco has adopted a robust technology – microseismic monitoring – that pinpoints where hydraulic fractures are induced.

Microseismic monitoring is a relatively new technology to Saudi Aramco for monitoring hydraulic fracturing. Microseismic events can pinpoint where the formation is sheared and can detect events to show excessive downward growth. Also, it can identify the occurrence and the azimuths of faults and natural fractures.

After analyzing the results from a well in a Saudi unconventional play, microseismic monitoring resulted in revising future fracturing designs. The fracturing treatment in the subject well was designed for a crosslinked fluid, creating excessive downward growth. Therefore, the team believes a slickwater treatment would be preferred to stay in the zone. Also, faults and natural fractures were observed around a stimulated area. Therefore, future fracture treatments will be placed away from these faulted and fractured areas to capitalize on stimulating the pay zone.

Microseismic monitoring has played a key role in optimizing upcoming fracture treatments, which in turn will affect future field development strategies, especially for unconventional plays. It is worth noting that this was the first time a horizontal well was used for microseismic monitoring for another horizontal well in Saudi Arabia.
Evaluation of Damage Mechanisms in Tight Gas Reservoirs: Field Example from Perth Basin
Authors: Bahrami Nick , Soroush Samaneh , Hossain Mofazzal , Lashari Arshad , Daloma Muhammad , Kabir Akim
Published: June 2015

Tight gas reservoirs represent a significant portion of natural gas reservoirs worldwide. Production at economical rates from tight gas reservoirs in general is very challenging not only due to the very low intrinsic permeability but also as a consequence of several different forms of formation damage that can occur during drilling, completion, stimulation, and production operations. Tight gas reservoirs generally do not flow gas to surface at commercial rates, unless the well is completed using advanced technologies and efficiently stimulated.

One of the major damage mechanisms in tight gas reservoirs is liquid phase trapping damage that is controlled by pore system geometry, capillary pressure, relative permeability and interfacial tension between the invading trapped fluid and reservoir fluid. The liquid invasion damage into the rock matrix reduces the near wellbore permeability as a result of temporary or permanent trapping of liquid inside the porous media, and results in low productivity in tight gas reservoirs.

This study presents evaluation of damage mechanisms in tight gas reservoirs and the methods that can provide improved well productivity by minimizing damage to the formation. Numerical reservoir simulation is integrated with tight gas field data analysis and core flooding experiments to better understand the effect of different damage mechanisms on well productivity in order to propose the possible remedial strategies that can help achieve viable gas production rates from tight gas reservoirs.
Chemically-Induced Pressure Pulse: A Novel Fracturing Technology for Unconventional Reservoirs
Authors: Al-Nakhli Ayman R.
Published: June 2015

The huge resources of unconventional gas worldwide along with the increasing oil demand make the contribution of unconventional gas to be critical to the world economy. However, one of the major challenges that operators face to produce from unconventional resources is commercial stimulation technique that creates sufficient stimulated reservoir volume. Unconventional reserves trapped within very low permeability formations, such as tight gas, or shale formations, exhibit little or no production, and are thus economically undesirable to develop with existing conventional recovery methods. Such reservoirs require a large fracture network with high fracture conductivity to maximize well performance.

One commonly employed technique for stimulating low productivity wells is multi-stage hydraulic fracturing, which is costly and typically involves the injection of high viscosity fluids into the well. Fracturing fluid by itself could form a damaging material for the fracture due to high capillary forces. Thus, additional needs exist for an economical method to enhance production within a tight gas formation.

This paper discusses a new stimulation method to increase stimulated reservoir volume (SRV) around wellbore and fracture area, and therefore, improve unconventional gas production. The method entails triggering an exothermic chemical reaction in-situ to generate heat, gas and localized pressure sufficient to create fractures around the wellbore. In controlled experiment, chemical reactants were separately injected into core samples with a minihole and upon mixing inside the core, an exothermic chemical reaction occurred and the resultant heat and gas pressure caused macro-fractures. NMR-porosity imaging showed significant increase in macro pores throughout the core. Additionally Large scale experiments using cement blocks with a simulated wellbore cavity were performed. Once the wellbore was filled with the chemicals and upon introducing a triggering catalyst an in-situ chemical reaction took place which generated heat and gas with sufficient pressure to cause shear fractures in the surrounding rock. These experiments showed extensive fractured and shattered pieces and also provided preliminary design requirements for a field test. The chemical reactants then incorporated into a fracturing gel to simulate creating additional fractured from the main induced hydraulic fracture. The results were very encouraging and the generated high temperature and pressure caused the gel to break thus it is concluded that this technique effectively contribute to fracture cleanup in addition to creating required SRV. The experiments were very successful in proving the new concept of generating SRV in tight gas well and the developed stimulation technique is fairly easy to implement in the field.
Adaptation of Modern Techniques in Economic Exploitation of Unconventional Gas Reservoirs in the Emerging Regions
Authors: Dusterhoft Ron , Sharma Puneet
Published: June 2015

Although the reported potential unconventional gas resource volumes in emerging regions (Middle East, North Africa, and South Asia) are almost similar or higher in size to North America, the exploitation of such resources has been very limited. Using North America as an analogy, unconventional gas production is proposed to drastically increase globally in upcoming decades. However, many challenges are associated with developing and evaluating unconventional resources.

Exploitation of tight-gas plays borrows extensively from a suite of technologies that are already available within the conventional oil and gas industry. However, there are several aspects of unconventional reservoirs that make them difficult to understand. New techniques are compulsory to demonstrate and evaluate this new era of hydrocarbon resource exploration.

Highly specialized designs and an integrated approach of all technologies are essential to unlocking these significant unconventional resources. Accomplishing efficient tight gas stimulation also requires paradigm shifts from what is currently being performed, particularly in the emerging regions, as most of the hydraulic fracturing processes presently being used heavily depend on large volumes of available water, and water scarcity is historical in many of these areas.

This paper highlights challenges associated with developing tight gas resources and the role of cutting-edge technologies to answer several pertinent questions about unconventional reservoirs. Also provided is a technical overview of the best strategies for field development to capitalize on the promising potential of these reservoirs. Additionally, alternative approaches are proposed that appear to be imperative to enhance the current stimulation technologies for tight gas formations. This can act as an enabler to address challenges presented by unconventional resources in the emerging regions and harness the trapped energy, which can work as a cornerstone to fuel the economic growth of the world.
Slim LWD Spectral Gamma Ray for Both Well placement and Petrophysical Evaluation of Clastic Reservoirs in Saudi Arabia
Authors: Zeghlache Mohamed Larbi , Palmer Richard , Abdelkader Alibassiouny
Published: June 2015

With the world's increasing energy demand, it has become more crucial to safely and efficiently maximize recovery from existing assets. In this effort, there are compelling reasons for focusing on clastic reservoirs where horizontal wells are drilled to maximize reservoir contact and drainage area. In this environment, well placement and real-time petrophysical evaluation are the keys to maximizing net- to-gross ratios.

Technology has recently evolved toward the adaptation of a multi-disciplinary approach and integration of real-time answer products to address formation evaluation challenges. To this end, Saudi Aramco has introduced into their lateral operations the slim size LWD spectral gamma ray in combination with the multi-functional logging while drilling (LWD) technology.

By measuring a formation's three naturally occurring radioactive components: potassium (K), uranium (U), and thorium (Th) in real-time, petrophysicists can identify clay mineral types in addition to the standard evaluation. This information allows for more accurate formation evaluation through reliable optimizing petrophysical modeling of mineral and fluid types and volumes. It also minimizes uncertainty on the volume of shale (Vsh) estimation, which has an impact on the effective porosity calculations.

From real-time 16-bin spectral gamma ray data and X-Y magnetometers to track the detectors azimuthal position, a high resolution image is preferred — over the standard gamma ray — for properly identifying target entry and for optimizing well trajectory in clastic formations where the lithology changes vertically and laterally.
Productivity Increase Estimation for Multi Stage Fracturing in Horizontal Wells for Tight Oil Reservoirs
Authors: Baig Mirza Talha , Alnuaim Sami , Rammay Muzammil Hussain
Published: June 2015

Hydraulic fracturing is widely used to exploit the tight and low permeability oil and gas reservoirs. With recent technological advances, horizontal wells, along with Multi Stage Fracturing (MSF) have come up with a great effective combined solution for tight reservoirs. The combined technologies overcome formation damage, increase reservoir contact, enhances productivity from fractures; hence make tight reservoirs development economical.

On the other hand, drilling a horizontal well with placing multi stage fractures along its lateral is an expensive job. The feasibility of this job should be done to analyze the productivity enhancement provided by the Multi Stage Fracturing before commencing drilling operation. This work developed a simple, easy to use empirical correlation to calculate oil productivity enhancement in terms of fold of increase (FOI) for Pre-Frac analysis. In this paper, an approach has been put forward to evaluate the FOI in Multi Stage Fractured system for horizontal wells in the form of a correlation. The approach used is based on two 3-D simulation modelling scenarios; one with hydraulic fractures and the other without. The fracture case has been run for a wide range of parameters like number of fracture stages, formation permeability, fracture spacing, fracture conductivity and fracture half length, while the other case was run with changing formation permeability only, which served as the base case. The productivity index for both cases corresponding to same formation permeability was used to compute FOI for all different scenarios.

A general empirical correlation for estimation of increase in oil productivity due to multi-stage fracturing in horizontal wells is derived through the use of multivariate regression. Correlation is obtained by 70% data points with the accuracy results of 5.20%, 0.54% and 7.79 Mean absolute percentage error, Mean percentage error and standard deviation respectively. The obtained correlation is tested against 30% of unused data points and found to generate acceptable results with 5.20%, 0.50% and 7.40 Mean absolute percentage error, Mean percentage error and standard deviation respectively.

The developed correlation is accurate enough to capture even the minor changes in flow inside wellbore as well as interference between adjacent fracture stages. It will serve as a handy tool for pre analysis of fracture performance as compared to the costly and time consuming analytical or simulation models.
A New Practice of Streamline Simulation for Compositional and Miscible Floods
Authors: Nagib Mohamed , Burns Alan , Ingham Derek , Al-Banbi Ahmed
Published: June 2015

Performance evaluation of miscible and near-miscible gas injection processes is available through conventional finite difference (FD) compositional simulation, which is widely used for solving large-scale multiphase displacement problems that always require large computation time. A step can be taken to reduce the time needed by considering low-resolution compositional simulation. The model can be adversely affected by numerical dispersion and may fail to represent geological heterogeneities adequately. The number of fluid components can possibly be reduced at the price of less accurate representation of phase behavior. Streamline methods have been developed in which fluid is transported along the streamlines instead of the finite difference grid. In streamline-based simulation, a 3D flow problem is decoupled into a set of 1D problems solved along streamlines, reducing simulation time and suppressing any numerical dispersion.Larger time steps and higher spatial resolution can be achieved in these simulationsparticularly when sensitivities runs are needed to reduce study uncertainties. Streamline-based reservoir simulation, being orders of magnitude faster than the conventional finite difference methods, may mitigate many of the challenges noted above. For gas injection, the streamlines approach could not provide a high resolution or adequate representation for the multiphase displacement.

In this paper, the streamline simulations for both compositional and miscible gas injection were tested, in addition, the conventional gas injection scheme and detailed comparison between the FD simulation and the streamline approachareillustrated. Also, guidelines of how streamline can be potentially used to visualize the effect of gas displacement are presented in this paper.