bluuebunny/crossref_metadata_2025 huggingface dataset:
NanoEmulsion for Non-Aqueous Mud Removal in Wellbore
Authors: See Chun Hwa , Saphanuchart Wasan , Nadarajan Sritharan , Lim Chia Ni
Published: May 2011

Efficient mud removal, filter cake removal and formation clean-up are critically required for well cementing, production and injection wells drilled with non-aqueous mud. Conventional surfactant clean-up system requires a turbulent flow and large volume to solubilize residue efficiently. Unsuitable surfactant system may cause emulsion blockage and oil-contamination in the completion brine, which consequently leads to a reduction in oil production rate. A new potential method to overcome these problems with higher efficiency to remove non-aqueous mud and filter cake is NanoEmulsion technology. This technology able to reduce the oil-water interfacial tension (IFT) down to < 0.001 mN/m, solubilize much larger amount of oily hydrocarbons without any mechanical stirring needed. This paper elucidates the potential of NanoEmulsion technology in removing non-aqueous based mud and filter cake during wellbore cleaning through laboratory scale set-up at ambient and HTHP conditions. The impact of temperature, pressure, mono- and divalent electrolytes, bridging agent such as calcium carbonate, acidity and polymers (Xanthan Gum and HEC) have been studied. It was found that the NanoEmulsion is effective in removing non-aqueous mud in all studied conditions at tested duration of < 10 minutes. The cleaning mechanism proposed are: (1) instantaneously reducing interfacial tension between oil-water and oil-solid surfaces, (2) emulsify and solubilized oil content, (3) facilitate wettability and allowing water molecules to penetrate in-between oil and solids surfaces, causing the oil to spontaneously repel from the hydrophilic solid surfaces, and (4) separation of oil from water and solids. This enables the recycle of the oil content which is free from solids. NanoEmulsion technology can be incorporate with acid to simultaneously dissolve calcium carbonate bridging agent and solubilize the oil in the filter cake. In addition, it is free from benzene, toluene and xylene (BTX), synthesis from bio-degradable natural sources, non-toxic, easy to handle, and 100% biodegradable.
Multizone Well Testing with Downhole Tools in Extreme Sour-Gas Conditions
Authors: Hollaender Florian , Salsman Alan , Neyaei Fardin Ali , Singleton Richard , Al Badi Fuad , Rigatos Efstathios , Ali Ashraf , Anwar Mohamed
Published: May 2011

A recently drilled appraisal well in a multilayered carbonate reservoir was successfully tested using downhole tools in very hostile downhole conditions. While the reservoir pressure and temperature were not excessive, the combined concentrations of hydrogen sulfide (H2S) and carbon dioxide (CO2) were well above anything that has been tested in the past with similar tools. Four different zones were tested individually using a fit-for-purpose test design, which allowed for testing two zones per trip. The services included downhole tools for shut-in and well-control purposes, bottomhole samplers, memory gauges, through-tubing perforating and coiled-tubing intervention through the test string to acid stimulate, N2 lift, and set cement plugs between zones.

The use of the downhole test string provided the means to carry out a complete well test with downhole shut-in and sampling controlled from the surface. The operational flexibility offered by the string allowed for all operations to be successfully performed even with lengthy exposures of the tools to sour fluids. This appraisal well is one of a series of wells drilled in this area but the first one in which very extensive data acquisition has been acquired thanks to a detailed well-test procedure and job planning.

This test required a significant amount of prejob planning, in addition to attention to detail in the execution and onsite preparation and maintenance. Our paper describes the test requirements, the prejob planning, and the execution that led to the successful completion of this well test in very hostile conditions, the first of its kind in this part of the world.
Altering Sweep Profiles during Waterflooding Using Near-Wellbore and Deep Reservoir Controls
Authors: East Loyd E. , Sierra Leopoldo , Soliman Mohamed Y.
Published: May 2011

Water, CO2, and steam flooding in oil wells are common today as many of the premium reservoirs are becoming significantly more difficult to efficiently produce. Much of the technology for optimizing the recovery in these assets revolves around well placement and production controls. When early flood-front breakthrough occurs, the options for improved asset economics are generally limited to near-wellbore controls to minimize the costs of producing, separating, and disposal of nonhydrocarbon production. Often, these controls have short-term effectiveness, and intervals or wells are prematurely abandoned. Altering flood fronts deep in the reservoir will offer much greater effect and longer-lasting control of nonhydrocarbon production. Successful alteration of the sweep pattern deep in the reservoir yields better sweep efficiency, lower operating costs and higher ultimate recovery.

This paper explores the benefits of well completions that incorporate a combination of near-wellbore and deep reservoir controls to modify the fluid-flow pattern when production coincides with an active water flood. By using numerical simulation of various completion methodologies with and without these controls, the benefits will become apparent. Optimization of these controls for a given completion will be illustrated for a single producer horizontal with vertical injector and for a producer pair of horizontals with a horizontal injector.
A new Method to Determine Marble Provenance with XRD Accessory Mineralogy
Authors: Lynn Jack D.
Published: May 2011

Calcium carbonate, used as a "sizing" material to aid in fluid loss control during drilling/completion operations, is supplied to Aramco in a number of different pre-ground diameters (e.g., Chips, coarse, medium and fine), by a number of vendor/suppliers. In order to provide "abrasion resistance" (in itself, a nebulous terminology), the drilling carbonate is specified to be supplied as "marble", i.e., metamorphic calcium and dolomitic carbonates. The problem to drilling engineers and fluid specialists has been certification of a supplied product as an abrasion resistant "marble" or simply a low strength, sedimentary limestone/dolomite. Determination of the source or "provenance" of a sample is critical to obtaining a quality product from vendors.

This specification as "marble" has inherent QA/QC problems in that standard XRD cannot differentiate metamorphic carbonate from sedimentary limestone/dolomite. Previous methods relied on petrographic examination (polarizing light microscopy) of thin sections of sufficiently large samples, impossible with finely ground material.

A new method of evaluating drilling carbonate samples to determine their mineralogical provenance has been developed, that can be used on solids of any size, even in samples of solids isolated from the drilling mud during drilling operations. The method uses XRD/XRF data generated on acid insoluble residuals of the drilling solids material. Paragenetic origin can be determined based on the accessory mineral assemblage, which is well defined in the literature. In addition, a new compositional ternary diagram has been introduced, termed the M-C-A (MgO-CaO-AL2O3).

Based on the new technique, 18 carbonate drilling samples were first evaluated for acid solubility, and the residual material (insoluble) used for assessment of mineralogical provenance. The new method has the following characteristics: The new method is a robust QA method for rapid determination of marble provenance.The new method is found to be able to differentiate mineralogical provenance in carbonate samplesThe new method can quickly screen samples for potential formation damage issues.The samples can come from a fresh batch of carbonate before delivery to the field sites, or the method can be applied forensically by taking samples from the mud pits and shakers for evaluation.Given a sufficient data base, the method will be able to identify IK and OOK quarry sources of metamorphic marbles supplied by vendorsThe method can be used for rapid QA on new IK sources of metamorphic marbleThe new method can be easily incorporated into a new standard procedure for drilling marble QA, which should include ○Solubility in 20 weight percent HCl○Mineralogy by XRD/XRF (bulk and accessory minerals, separately)○Particle size distribution○Crush resistance (e.g., particle attrition tests)

The new method will provide a quick and effective method to certify drilling carbonate as marble, thus having the accepted abrasion resistance.
The Importance of Production Logging Sequence When Designing Inflow Control Completions
Authors: Lauritzen J. Eric , Al-Julaih Ali H. , Al-Momin Ali , Shahreyar Noman , Young Dustin
Published: May 2011

Production logging at multiple rates is used to correlate passive inflow device (ICD) completion designs to actual downhole flow rates for performance validation and design improvement. Accurate steady-state multi-rate production logging is quantitative proof of design for completion evaluation. When low rates are recorded first in wells that have not been fully unloaded, and then are followed up with high rate passes, the PI per compartment values may change due to unloading. When this occurs, the simulations will not match both rate curves because the production profile has changed in the time it took to log the two rates. Unloading at high rates may result in rapid wellbore cleanup, and the production-profile changes that are due to the cleanup rates will be evident. When this occurs, the utility of the lower rate PLT dataset is greatly diminished. This paper discusses the importance of performing production logging tests for the evaluation of flow contribution in ICD completions. Sandstone and carbonate case studies are presented that will illustrate the benefits of using a properly sequenced logging strategy for ICD completion performance evaluation. Multi-rate and high-to-low rate-production testing is highlighted, since it has resulted in improved well clean up and productivity. Multi-rate production logging also helped to differentiate between non-productive and the damaged zone sections along the horizontal. This comparison verifies the value gained for operators when an appropriate production-logging test design is put into practice.
Use of the Memory Concept to Investigate the Temperature Profile during a Thermal EOR Process
Authors: Hossain M. Enamul , Abu-Khamsin Sidqi A. , Al-Helali Abdul-Aziz
Published: May 2011

Accurate prediction of the temperature profile within a reservoir undergoing a thermal recovery process is a key factor in process design, production forecasting and reservoir management. Such profile is governed by the heat transfer between the rock matrix and flowing fluids, which is highly dependent on the thermal and rheological properties of the rock and fluids involved. In this work, the role of temperature-dependent rock and fluid properties in the development of the temperature profile during the thermal process was investigated employing the continuous time function as "memory." Mathematical models were developed in terms of a group of heat transfer dimensionless numbers that correlate the varying rock and fluid properties. New heat transfer dimensionless numbers are proposed which can be characterized by rock and fluid properties. The model equations were then solved numerically through MATLAB programming to produce temperature profiles for a typical steam flood where the rock and fluid temperatures are assumed unequal throughout the reservoir, i.e. the rock does not attains the fluid temperature instantaneously. Results reveal the development of a temperature profile within the growing condensed water zone that is flowing ahead of the steam zone. The rock and fluid temperature profiles were found sensitive to the rheological properties, time and fluid velocity. The proposed model would be useful for better prediction of reservoir performance.
Raman Spectroscopy Yields New Discovery of Reaction of Acetic Acid with Calcite
Authors: Qiu X. W. , Chang F. F.
Published: May 2011

Stimulation of high temperature oil and gas wells with HCl could cause significant corrosion to tubular goods. Organic acids are viable alternatives to HCl. However, conventional wisdom teaches that organic acids do not spend to its full capacity due to CO2 in solution. This leads to reducing their carbonate dissolving capacity further. Another potential drawback of using organic acids is the precipitation of the salt of calcium and organic ligands. Consequently, the concentration of the organic acid has to be confined to prevent the precipitation. Due to the above reasons, along with their cost per mass of rock dissolved, organic acids often have limited use in well stimulations.

Recent thermodynamic modeling studies have shown that when an organic acid or a mixture of HCl and an organic acid reacts with calcite, a previously unrecognized reaction occurs. This reaction enhances the calcite's dissolving capacity by the organic acid. The model provided new insight into the reaction equilibrium between organic acids with calcite, and gave a better understanding of which chemical species plays the dominant role in driving the overall dissolution reaction. In the case of acetic acid reacting with calcite, the model found that a chemical species, ca-monoacetate (Ca(CH3HCOO)+), exists because of the association of acetate and calcium ions. This species cannot be ignored. When quantitatively concentrated, it results in higher acetic acid dissolving capacity. Furthermore, mixing acetic acid with HCl can increase the conversion of acetic acid by the same calcium and acetate ion association and lead to more complete spending of acetic acid. The objective of this paper is to present the evidence of the existence of calcium monoacetate through experimental studies using Raman spectroscopy. Results showed that ca-monoacetate does exist during acetic acid dissolving of calcium carbonate. However, quantitative match between the experimental data and thermodynamic model prediction remains uncertain.
Drilling Hazards Diagnosed and Solutions Were Provided to the Northern Iraq Fields Utilizing Geomechanics
Authors: Gao J. , van Galen M. , Chou Q. , Neil B. , Soroush H. , Qutob H. , Mahli Z. , Abalioglu I.
Published: May 2011

The integrity of the wellbore plays an important role in petroleum operations. Hole failure problems cost the petroleum industry several billions of dollars each year. Prevention of wellbore failure requires a strong understanding of the interaction between formation strength, in-situ stresses, and drilling practices. As in-situ stress and rock strength cannot be easily controlled, adjusting the drilling practices is the usual way to inhibit wellbore failure.

Drilling in the problematic Kolosh formation in Kurdistan has always been associated with several wellbore stability problems. This has caused large amounts of non-productive time to drilling programs and the drilling of sidetracks in some of the wells in this field. A review of the drilling reports and dual-caliper logs from offset wells in the area revealed large amounts of washouts in the middle Kolosh section. These indicators demonstrated the requirement for performing a geomechanical modeling and wellbore stability study to mitigate such problems in future drilling operations.

In this paper, local in-situ stress magnitudes, orientations, and formation pressures were characterized. For this purpose, data was analyzed from offset wells (e.g., borehole breakout data, bulk density logs, wireline formation tests, drillstem tests, pressure build-up tests, formation pressure data in this area). The mechanical properties of the formation (including dynamic and static Young's modulus, Poisson's ratio, and rock strength) were evaluated using sonic, density, and gamma ray logs. A rock mechanical properties database and data management software was applied to correlate the calculated dynamic elastic properties to the most appropriate static rock strength and stiffness parameters for a base case wellbore stability model and subsequent sensitivity analyses. 2D elastoplastic and 3D linear elastic models were used to back-analyze the hole collapse and enlargement in the selected offset wells to evaluate and calibrate the geomechanical model. Wellbore stability software was used for this purpose. Finally, a mud weight window was defined, and the optimum profile of the mud weight was recommended for drilling through the Kolosh formations. Due to a narrow mud weight window, additional potential problems were investigated including the possibility of fracturing at the top of Kolosh formation. Finally, relevant solutions were presented.
Innovative In-Situ Reservoir Stress Test Helped to Manage and Optimize Water Disposal under Fracturing Conditions in South Oman
Authors: El Msallati S. , Hammad K. , Priyandoko P. , Cig Koksal
Published: May 2011

One of the major fields in the South of the Sultanate of Oman produces oil at 94% average BSW. All produced water is disposed of without treatment into the same aquifer. The disposed water is injected under fracing conditions and takes place more than 200 m below the lower shale (cap rock) in the sandstone (Fig.1). However the failure of the field's cap rock could result in oil deferment and the contamination of the overlying aquifer; therefore rigorous risk management is strongly required.

Several in-situ stress testing (mini-frac) stations were conducted in the field focusing on lower shale and sandstone formations to evaluate the risk of breaking the cap rock and above formations associated with the water disposal. However this was very challenging using the normal ways of testing; hence the stress testing application was conducted with an oil based viscous fluid. The viscous fluid allowed accomplishing the objectives in higher permeability and shale zones. The oil based viscous fluid facilitates initiation of a fracture in highly permeable sandstone formations and reduces the osmosis and plastic behavior effects in shale zones.

The viscous fluid stress testing provides the results required to update the numerical models for each formation by obtaining minimum stress and fracture initiation, propagation, and closure pressures (frac gradients). Moreover the test results will help to build models that can predict fracture growth while injecting water.

This paper will discuss in detail the viscous fluid stress test and how the results can be used to understand the reservoir behavior. Realistic injection forecasts were made possible using commercial fracture simulation software and some analytical and diagnostic methods based on pressure survey and injection volumes history.
Deblending the Simultaneous Source Blended Data
Authors: Huo Shoudong , Tsingas Constantine , Kelamis Panos , Xu Hai , Pecholcs Peter
Published: May 2011

Recently, the concept of simultaneous source acquisition (Berkhout, 2008; Beasley et al., 1998) showed that can significantly enhance field acquisition efficiency and at the same time due to the increased seismic data sampling improves seismic image quality. In 2010 Saudi Aramco by employing a fixed active super spread continuously recorded 18 single vibrators operating simultaneously in 18 separate quadrants. During this test over 45,000 vibrator points were acquired in 24hr field operation. The source blended acquisition field test aimed in the optimization of the following field acquisition parameters: high source density, unique up-sweep length and source distance separation. For blended data since all the sources were acquired at different times, the characteristic of interfering noise appears random in certain data sorting domains such as the common-receiver, common-offset, cross-spread and CMP. Stacking and migrating the blended seismic data without any further denoising produces acceptable results as stacking can effectively suppress random energy. However, additional efforts towards crosstalk separation have been proposed so that deblended pre-stack data can be further processed for amplitude and reservoir characterization analysis. In this paper, we illustrate suitable processing techniques and workflows in order to attenuate source interference noise so that the simultaneous sources can be separated effectively into equivalent data sets for further pre-stack processing. Comparisons with conventionally acquired 3D seismic data in the same area are also presented.
Optimizing The Planning, Design And Drilling Of Extended Reach And Complex Wells
Authors: Agbaji Armstrong Lee
Published: May 2011

Extended Reach Drilling (ERD) is an integrated methodology for drilling high-angle wellbores with long horizontal displacements. Several problems are associated with extended reach wells. Thus for high levels of performance improvement to be achieved, it is essential to analyze the interrelationship among the elements involved in the entire drilling process. This is because a system that considers the individual elements of the drilling system in isolation is inadequate to deliver desired performance improvement.

In this study, an algorithm that sets forth a design for a drilling program that is suitable to drill an extended reach well was developed using Visual Basic. Although the algorithm touches on several factors affecting extended reach drilling, the major focus is on the six elements, which are considered the critical factors. These are: Well Trajectory Design, Bottom Hole Assembly (BHA) Design, Bit Hydraulics, Drill String Design, Torque and Drag, Hole Cleaning and ECD Management. The proposed algorithm evaluates the interrelationship among these critical factors and provides direction on the processes and tasks required at all stages in the design and drilling of an ERD well to achieve maximum drilling performance. The development of the model is based upon information gathered from several sources, many new ideas from technical publications, along with information and feedback from field-based personnel. The output generated from the model compare well with results from actual field data.
Recovering Flowing History from Transient Pressure of Permanent Down-hole Gauges (PDG) in Oil and Water Two-Phase Flowing Reservoir
Authors: Shiyi Zheng , Fuyong Wang
Published: May 2011

Permanent Down-hole Gauges (PDG) have been widely installed in oil and gas reservoirs. These systems monitor the real-time down-hole information continuously. In this way, real time reservoir management and production can be significantly improved.

The key in analysing long term transient data from PDG is the flowing rate history. Accurate flowing rate history is not always available in oilfield, especially in the multiphase reservoir. The multi-phase flow meters are not only expensive but also inaccurate and unstable. The common practice is that several wells are measured together through manifold, and total cumulative production is given without flowing rate details for each individual well. How to recover accurate flowing rate history is a challenge for reservoir engineers.

This paper presents the study results of recovering flowing rate history using the Wavelet Transform (WT) method in oil and water two-phase flowing reservoir. At first, the transient pressure from PDG is processed by HAAR wavelet. The WT will yield frequency amplitude changes when flow events happen, so the time of flow events will be identified. Then, with the relationship between liquid rate change and the corresponding WT frequency amplitude changes, the flowing rate history can be recovered with high accuracy.

The developed algorithms were demonstrated through two kinds of simulation models, i.e., constant water cut and increasing water cut after water breaking though. In addition, the relationship between water cut change and WT frequency amplitude is developed. The effects of skin, wellbore storage and reservoir heterogeneities are considered, and the study results have demonstrated the robustness of this method and its promising future application in practice.
Effective Reservoir Management Strategies to Revitalize Dead Producers Behind the Flood Front
Authors: Abuhassoun Amer H. , Sequera Bernabe A.
Published: May 2011

Saudi Aramco has employed horizontal sidetracking on existing dead vertical wells to enhance wells’ productivity and rejuvenate field's performance. Understanding flood front movement, inter-reservoir connectivity, and pressure propagation in a highly stratified clastic reservoir in mixed fluvial and aeolian depositional environments are the key parameters that led to successful deployment.

This paper will present a case example discussing development strategies to revive an idle vertical well that was shut-in due to high water cut and low oil productivity. Both dynamic and static data were integrated to describe fluid flow phenomenon in the area to provide better understanding of the geological model, sweep and oil recovery. The multidisciplinary study indicated lateral and vertical reservoir heterogeneity and multilayer reservoir compartmentalization that caused uneven flood front movement and inadequate pressure support.

The team has considered all the uncertainties involved and have formulated an optimum completion plan. The team recommended sidetracking the idle well about 1 km away to target a sweet spot through an aggressive step-out strategy. This long step-out strategy was the first to be implemented in this sandstone reservoir where risk of hole collapse or stuck pipe is extremely high. Prudent reservoir monitoring and applying safe drilling and mud management practices were the major elements to successfully achieve the objectives. The plan was carefully executed by deploying fit-for-purpose completion that consisted of premium sand screens and blank pipe with mechanical packers to isolate a wet zone. The well was then treated with a clean-up fluid to remove any mud filter-cake to enhance productivity. The current production performance exceeded expected rate by 100%. The success and the captured lessons-learned from this strategy will be capitalized on for implementation in future similar sidetrack opportunities.
A New Nuclear Method to Locate Proppant Placement in Induced Fractures
Authors: Duenckel Robert J. , Smith Harry D. , Chapman Mark A. , Saldungaray Pedro
Published: May 2011

Traditional proppant placement evaluation in hydraulically induced fractures utilizes detection of radioactive tracers pumped downhole with the "frac" slurry. Although this technique has proven useful, it involves environmental, safety, and regulatory concerns/issues. The fracture height determination method described in this paper eliminates downhole placement of radioactive materials. A high thermal neutron capture compound (HTNCC) is inseparably incorporated into each ceramic proppant (CEP) grain during manufacturing in sufficiently low concentration that it does not affect mechanical strength, conductivity, durability, or density of the particles. The proppant is detected using standard compensated neutron logging tools (CNT) and/or pulsed neutron capture (PNC) logging tools, with detection based on the high thermal neutron absorptive properties of the compound relative to downhole constituents. Since the HTNCC is placed permanently in the proppant, logging for proppant detection can occur at any time(s) after the frac job, with no requirement for special handling or mixing considerations. To clarify, the new detectable proppant is not radioactive, and the benign detectable material is uniformly mixed into the ore during proppant manufacturing, so there is no chance for segregation of the detectable agent from the proppant.

Specifically, the proppant is detected using after-frac CNT logs, sometimes combined with corresponding before-frac logs. The increased thermal neutron absorption by the HTNCC reduces count rates in the near and far detectors, with approximately the same percentage reduction observed in each detector, leaving the near to far detector count rate ratio (N/F ratio) unchanged. One detection method utilizes a comparison of before-frac log count rates and after-frac count rates, with reduced after-frac count rates observed in zones containing proppant. Another detection method, especially useful if formation gas saturations change, requires only the after-frac log. Since the N/F ratio is essentially unaffected by proppant, after-frac count rates predicted from the ratio will also be unaffected. These synthetic count rates will be greater than the observed after-frac count rates in intervals containing proppant. When PNC tools are utilized in a third method, tagged proppant can be identified from count rate suppression in the detectors and also from increases in the measured formation and/or borehole component capture cross sections. In tools utilizing spectral gamma ray detectors, the HNCC may also be detected using capture gamma ray spectral deconvolution.

Monte Carlo modeling data are presented demonstrating the utility of these techniques employing CNT tools. Field examples illustrating proppant detection using compensated neutron tools are also presented.
The Aramco Method – Its Drilling and Production Engineering Significance
Authors: Amanullah Md. , Bubshait Abdulaziz , Allen Tim , Foreman Darrel
Published: May 2011

A new laboratory method defined as the ‘Aramco Method’ developed by Saudi Aramco Scientists can play a pivotal role to reduce the mud related formation damage, enhance the oil and gas production and improve the return on investment. The experimental results produced by the method will provide a comparative assessment of the relative stability of different sized bridging materials that are available for non-damaging drill-in fluid formulations. The method provides a useful tool to select the most suitable and highly durable bridging material for designing and developing superior drill-in fluids to eliminate or reduce mud related formation damage while drilling.

Preliminary experimental results produced by the method using a commercially available sized bridging material indicate significant variation in the PSD (particle size distribution) curve of sized bridging materials after testing due to the attrition effect and thus indicate a change in designed particle size distribution in down hole conditions. Material showing significant variation in the PSD due to the attrition effect during the test has the highest potential to cause formation damage. In case of low attrition resistant sized bridging material, there is a need to discard significant volumes of drilling fluid and to build fresh fluid in order to add new sized bridging material in the drill-in fluid system frequently to restore the desirable particle size distribution. On the other hand, material showing no or negligible variation in the PSD due to high resistance to attrition damage has the lowest potential to cause formation damage. Due to the preservation of the PSD of high attrition resistant bridging material for a long time, the drill-in fluid containing such material needs only infrequent addition of additional sized bridging material in the drill-in fluid system to maintain the desirable particle size distribution and eliminate or reduce the formation damage potential of the drill-in fluid. The engineering significance of the method is that it will provide a guiding tool to select the most suitable sized bridging material to reduce the formation damage potential of drilling mud while drilling and improve the well productivity while producing. The economic significance of the method is that it will reduce the mud management cost and enhance the return on investment by improving the ultimate recovery of oil and gas resources
Cementation Exponent Estimation for Complex Carbonate Reservoirs Using a Triple Porosity Model
Authors: Al-Ghamdi Ali , Aguilera Roberto , Clarkson Christopher R.
Published: May 2011

A previously defined triple porosity model is used to calculate the cementation exponent (m) of complex carbonate reservoirs in the Middle East using well log data. The cementation exponent is usually affected in carbonate rocks by different types of primary and secondary porosities. A combination of interparticle porosity, non-connected porosity (e.g., vuggy and fenestral) and fractures increases the uncertainty in the estimation of m. Therefore, a well-defined petrophysical approach must start by first understanding the rock's fabric.

Initially, samples are classified into different flow units based on pore throat apertures at 35% cumulative pore volumes (rp35). This classification is then extended to include variations in porosity types based on geological and petrophysical descriptions of each rock. Each sample has different proportions of connected and non-connected porosities. These porosities are defined as matrix, fractures and non-touching vugs (including fenestral porosity). The porosity types are extracted from well logs for the whole reservoir section and are cross-checked against core samples and thin sections.

The value of m in a triple porosity system can be larger, equal, or smaller than the cementation exponent of only the matrix blocks (mb). This variation depends on the relative contribution of natural fractures and non-touching vugs compared to the composite triple porosity reservoir. A continuous curve of m values is obtained using this model. A good comparison has been obtained between the results of this model and m values measured in the laboratory.

Estimation of variable m values within short distances in a given reservoir using the triple model is a significant development in formation evaluation that helps reduce uncertainty in petrophysical calculations. The results increase the confidence level in water saturation and reserves determinations.
Opportunities/Lessons Learnt and New Technologies for Redevelopment of a Mature Field
Authors: Trebolle R. , Hamdan V. H. , Sepulveda W. , Whitney P. , Grigorescu R. , Mohammad Afzan , Kadir F. A. , Tusimin F. Bt. , Curteis C.
Published: May 2011

In general, mature oilfields have a good portion of the remaining reserves still trapped due to inefficient drainage, production decline, increase in water cut and sand production and aging of the existing systems. This paper addresses techniques and initiatives to optimize development plans in a mature field. For Bokor Field in particular, there have been identified and implemented opportunities such as Infill drilling and workover optimization, dynamic underbalance perforation (DUP), matrix acidizing and propellant stimulation, water shut-off mechanical (WSOM), sand management, through tubing stand alone screens, deployment of electrical submersible pumps (ESP) and gas lift NOVA valves, real time surveillance (DHG, DTS and LiftWatchers*) and optimization, and microbial EOR.

Before the implementation of these techniques, this field had a daily oil production equivalent to 10 MSTBD (after fields decline) and the current production is 26 MSTBD. The two main reason for this increase are: New technologies were employed in this oil field with dramatic results incorporating new hydrocarbon reserves, via 3D seismic techniques, high resolution stratigraphy and better static and dynamic simulation models.Multidisciplinary integrated studies to increase field ultimate recovery factors by improvements in drilling, workover, stimulations, facilities and EOR methods.
Simulation Study on Surfactant-Polymer Flood Performance in Fractured Carbonate Reservoir
Authors: SayedAkram Nawaf I. , Mamora Daulat
Published: May 2011

This paper presents a comprehensive simulation study on the impact of natural fractures on the performance of surfactant polymer flood in a field wide scale. The simulation model utilized for the study is a dual porosity dual permeability model representing 1/8 of a 20-acre 5-spot pattern. The model parameters studied include wettability alteration, interfacial-tension changes and mobility reduction effect. The results of this study clearly indicate the importance of reservoir description and fracture modeling for a successful surfactant-polymer flood. This may lead in huge difference in reserves booking from such EOR method.

Naturally fractured carbonate reservoirs are usually characterized by mixed wettablility and low matrix permeability which leads to low oil recovery and high remaining oil saturation. Enhanced oil recovery methods such as surfactant-polymer flood (SPF) enhance the recovery by increasing the spontaneous imbibitions either by lowering the interfacial tension or altering the wettability in the matrix. However, one of the main reasons for failed surfactant-polymer floods is under-estimating the importance of the reservoir and fluid characteristics especially the description of natural fractures and their effect on recovery.

Sensitivity runs were made in field size scale in order to compare oil recovery by capillary force, buoyancy force and viscous force. The simulation study indicates a relationship between water saturation and the start of altering wettability and/or interfacial tension to maximize oil recovery. Also, when a surfactant alters the rock wettability, an optimum IFT should be identified for faster and higher imbibitions. In addition, the study shows effect on recovery by permeability contrast between that of the fracture and that of the matrix as well as fracture orientation with respect to injector-producer direction.
Automated Technology Improved the Efficiency of Directional Drilling in Extended Reach Wells in Saudi Arabia
Authors: Kragjcek Roberto H. , Al-Dossary Abdullah , Kotb Waleed , Al Gamal Abdelsattar
Published: May 2011

With the focus on continuous drilling optimization, a collaborative effort was implemented to analyze and assess drilling challenges encountered while drilling extended horizontal wells in the Khurais field in Saudi Arabia. The primary requirement was to enhance the efficiency of conventional downhole motor directional drilling systems in the challenging horizontal reservoir section.

The Khurais field is located in a remote area in the central part of Saudi Arabia approximately 200 km from the Saudi capital Riyadh, and 300 km from the Eastern port city of Dammam. The producer wells are drilled in the middle of the field and the water injector wells are drilled close to the field boundaries.

An average of 12 rigs worked simultaneously throughout the duration of the project to drill and complete the required increment wells. The horizontal wells are comprised of the producers, trilateral producers and power water injectors. The wells were drilled to an averaged measured depth of 14,000 ft, with an average of 6,500 ft of open hole section across the reservoir. The 6⅛" horizontal hole section is particularly challenging and is drilled with steerable mud motors with the assistance of real time geosteering and logging while drilling (LWD) tools to maintain the horizontal open hole section of the well close to the top of the reservoir within a window of 3 ft.

The fracture intervals coupled with high permeability makes the drilling of this section particularly challenging, as mud losses are frequently encountered in this section. The main difficulties to improve the efficiency of the directional drilling process were high drag and differential sticking.

To overcome the challenges mentioned above, the drilling team utilized a new sliding technology that interacts with the drilling rig top drive to break the static friction improving the weight transfer to the bit, and thereby increase the rate of penetration (ROP). Through the virtual elimination of differential sticking and reduction of buckling problems, this system smoothly helps to deliver weight down to the bit. Additional benefits of this innovative technology are the prevention of stalling of the mud-motor, steady orientation of tool face and easier steering.

The authors will describe the innovative system utilized to improve the ROP during the sliding process by almost 50% and will present real cases supported by field data. They will also illustrate the importance of post-actions review and rig crew training in the achievement of record ROP in sliding mode. Historical cases will be presented and the benefits of the application of this technology in these wells will be explained.
Surface Tension of Spent Acids at High Temperature and Pressure
Authors: Saneifar M. , Nasralla R. A. , Nasr-El-Din H. A. , Fahes M. , Hill A. D.
Published: May 2011

Spent acid accumulation in the wellbore area after acidizing causes severe formation damage resulting in loss of productivity. This would cause reduction of relative permeability to gas, especially in tight gas wells. Capillary forces are the key parameters that affect the trapping of spent acid in the formation. This work provides a comprehensive study of the effect of acid additives in spent acid on surface tension in tight gas carbonates. All experiments were conducted using Drop Shape Analysis (DSA) at high temperature and pressure.

Different types of commonly used acid additives including corrosion inhibitors, iron control agents, mutual solvents, methanol, acetic acid and formic acids were tested at different concentrations. Experiments were conducted at 1000 psi and temperature ranging from 25 to 150 °C.

Acid additives such as methanol and corrosion inhibitors reduced surface tension. However iron control agents, formic and acetic acids had no impact on surface tension. In addition, increasing temperature resulted in reduction of surface tension.

A unique feature of this work is that measurements were conducted at high temperature and pressure. This work contributes to the knowledge of surface tension behavior of different acid additives. Consequently, that would help in better designing the acid formulae used to enhance well productivity by minimizing capillary forces.
Drilling Solutions to Improve Performance in Deep Gas Drilling in Saudi Arabia
Authors: Nawaz Khalid , Kubaisi Abdallah A. , AbdRabAlreda Saeed H. , Verma Jaywant , Ganda Sukesh
Published: May 2011

Directional drilling in the deep gas fields of Saudi Arabia is very challenging because of the hard formations and harsh drilling conditions. The formations encountered are primarily hard limestone and dolomites interbedded with anhydrite. This paper describes various drilling solutions implemented in deep gas drilling. These solutions include: Successful introduction of open hole sidetrack (OHSDTR) technique to drill multilateral horizontal wells.Implementation of Powered Rotary Steerable System (PRSS) in Khuff and Pre-Khuff formations.Drilling Optimization to enhance drilling performance.

Conventionally, whipstock technique was employed for drilling dual laterals. Saudi Aramco and Schlumberger D&M jointly came up with the idea of drilling dual laterals using an OHSDTR technique to avoid complication due to whipstock failure. First successful dual lateral horizontal Khuff-C gas producer drilled with the open hole sidetrack technique, saved $975,000 and two weeks of rig time. It also helped in getting rid of time consuming whip stock operation which sometimes even resulted in loosing entire lateral due to unsuccessful whip stock retrieval.

With PRSS, the company was able to drill both vertical and curve sections in one run, maximize rate of penetration (ROP), and increase footage per bit run while meeting directional requirements. Successful development of the PDC bit in conjunction with the PRSS system led to record runs in all deep gas fields. Casing-to-casing sections were drilled with an improved ROP of approximately 97%, compared to that of a conventional motor. The integrated power section played a key role in improving penetration rate. In addition to tangible time savings, it offered benefits such as reduced tortuosity and better hole cleaning.

This paper reviews the design and optimization processes that when developed resulted in improved drilling performance, significantly reduced rig days and enabled early delivery of the wells in challenging deep gas drilling in Saudi Arabia.
A Novel 4-D Reservoir Simulation Workflow for Optimizing Inflow Control Device Design in a Giant Carbonate Reservoir
Authors: Ogunsanwo Oloruntoba , Lee Byung , Wahyu Hidayat , Leung Edmund , Gottumukkala Varma , Ruan Feng
Published: May 2011

The newly developed workflow is based on a 4-D sector modeling study on a west flank of Field A, offshore Saudi Arabia. The approach involves the use of time-lapse monitoring of reservoir saturation profile for injectors and producers as well as 4-D water flood front movement in the reservoir to understand dynamic reservoir challenges. These challenges are zones with future water breakthrough, dynamic injection/production interaction, impact of reservoir drive mechanism on well injectivity or productivity, initial and future reservoir conditions.

With this understanding, rate optimization process is performed on the open hole injectors and producers. Thereafter, completion is optimized to achieve uniform influx profile, flow restriction and zonal isolation where required along the horizontal section. Four different completion strategies were evaluated by alternating between Inflow Control Devices (Nozzle based) completion and open hole in injectors and producers.

Even though the sector model used in this study is subject to further calibrations as more geological, petrophysical and production data become available; the study outcome based on the novel workflow demonstrated the challenges involved in making a completion strategy with ICD's in injectors and producers. The results showed an incremental cumulative oil gain of (5%) with a one year delay in water breakthrough over a period of 20 years. It also indicated that further improvement in oil recovery can be achieved by ICD completion above that achieved in the rates optimization process of injectors and producers. The study showed a positive indication that ICD completion is beneficial in challenging reservoirs with mobility ratios considerably greater than one. The industry should consider a novel 4-D well – reservoir integrated modeling approach to making completion strategy and evaluating ICD completion design prior to deploying them in a field wide campaign.
A New Approach to Classify Microporosity in Miocene Carbonate Reservoirs of Offshore Sarawak, Malaysia
Authors: Rahman Md. Habibur , Pierson Bernard J. , Yusoff Wan Ismail
Published: May 2011

Microporosity can occur in grain, cement or matrix and it is related to the depositional and diagenetic history of the carbonate reservoir. Depending on the crystallometry and morphometry of micrite particles, microporosity can vary both in amount and in nature. Different kinds of micrite microtextures may produce different kinds of microporosity. This study proposes a classification of micropores and micrite microtextures. We propose a classification that includes four micrite microtextures in Miocene Carbonate reservoirs, offshore Sarawak, Malaysia. Rounded, subrounded, microrhombic and polyhedral, and compact anhedral micrites have their distinct crystal morphology and crystal contacts. This microtexture classification of micrite particles can explain the occurrence, distribution and abundance of microporosity in Miocene carbonates. Based on the crystallometry, morphometry and textural arrangements of micrites a classification scheme is proposed that includes four different classes of micropores such as very fine, fine, medium and coarse micropores with a maximum pore diameter of 0.1 to 2 micrometer, 2 to 4 micrometer, 4 to 6 micrometer and 6 to 10 micrometer respectively. Microporosity affects the empirical porosity-permeability relationship in carbonate reservoirs and influences the assessment of ultimate recovery of hydrocarbon. The application of microtextural classification of microporosity can explain the scattering of data points in porosity-permeability crossplot.