bluuebunny/crossref_metadata_2025 huggingface dataset:
Comparison of a New Multi Laterolog Tool and a Formation Resistivity Imager in the Phiops Field of Egypt
Authors: Abdel-Shafy T. , Fattah A. , Corley B. , Khokhar R. , Maurer H.
Published: September 2011

The Multi Laterolog is a newly developed array laterolog logging device based on the Dual Laterolog principle, consisting of four independent focused measurements of differing depths of investigation with high vertical resolution. A model-based adaptive borehole correction (ABC) technique corrects the Multi Laterolog measurements for borehole effect in very conductive muds and large boreholes by solving for tool position as an unknown. This approach guarantees that in non-invaded intervals, all four laterolog curves are properly "stacked", even in large washouts, while invaded intervals show a consistent resistivity profile. The correction algorithm is very fast and is applied in real time during data acquisition. It also provides an estimate of true formation resistivity (Rt) that can be significantly higher than the deepest laterolog measurement. This results in a more accurate estimation of hydrocarbon saturation. With the addition of a micro-resistivity device, it is also possible to estimate the length of mud filtrate invasion (Lxo).

Advantages of the new Multi Laterolog logging tool and advanced processing principles in combination with other wireline logging tools like the Formation Resistivity Imager are illustrated by an example from the Phiops field in Egypt.
Accelerating Interactive Seismic Applications Using Fast Sorting Algorithm
Authors: Al-Dossary Saleh , AlSharikh Abdulaziz , Aramco Saudi
Published: September 2011

Many seismic processing algorithms require trace and/or meta data ordered in a specific domain. Sorting large 3D surveys can take days even using a large supercomputer. If an efficient sort technique is not available, users may avoid trying new seismic processing algorithms that require sorted data.

We introduce a modified merge-sort, which runs 3 to 4 times faster than Intel standard C runtime library quick sort algorithm. Our new technique improves on Donald Knuth's adaptation of John Von Neumann's 1945 classic merge sort [1] in two areas: memory management and code parallelization. Memory management is improved using pre-allocated arrays. Parallelization is performed using OpenMP.
Management of the Disastrous Underground Blowout in South of Iran
Authors: AShena Rahman , Amani M. , Taei B. , Kamyab M.
Published: September 2011

An underground blowout is defined as an uncontrolled flow of formation fluids from a high to a low pressured zone.

Due to the 9 5/8" casing collapse of the well no. X of MARUN Field with great tectonics, in the upper part of Aghajari Formation, Lahbari at 687 m depth, the formation oil and gas penetrated to Lahbari (with a large permeability and low formation mineral cementing) and appearing at the surface as 50 seeps (underground blowout). Most seeps were only 4 kms away from Jarahi River supplying the drinking water of three towns and additionally flows to Iran' Largest Wildlife Refuge, Shadegan Refuge which is home to a large number of flora and fauna species. The gas was set ablaze by the emergency crew to secure the environment from gas spreading and explosion.

The identification of the GPS seep coordinates and slope to the river, Construction of 31 soil dams in 3 days to accumulate oil in case of flows towards the river, establishment of a 85 m wide floating bridge after the heavy rain, application of a large number of busters, day and night operation of 1800 NISOC, UBD and emergency workers to cap the well were only part of these huge operations. Comprehensive geology, drilling and production history, incident, well capping and also especially HSE operations including future amendments would be described.

Inexistent well integrity management (WIM) to monitor leakages, casing corrosion erosion, and cement quality after 34 years of production would be presented as the main reason of the blowout while. The evidence presented clearly shows the disobeyance of the contemporary drilling manager in not extending the 13 3/8" intermediate casing to 1200 m depth according to the geological well forecast. The previous 9 5/8" casing design was confirmed after designing it again.
A Successful Introduction of a New Tools Configuration and Analysis Method for Production Logging in Horizontal Wells
Authors: Torne Juan , Arevalo Francisco , Jay Phil , Eid Mahmoud , Guergeub Nacer , Frisch Gary
Published: September 2011

During the last two decades, the efficiency and economy of horizontal wells have significantly increased owing to the successful introduction, adoption, and application of new technologies. Proper planning and economic evaluation of proposed horizontal wells requires sufficiently accurate geological and reservoir modeling. Without such an approach, the economic success of any horizontal well should be considered a high risk.

Production logging data in both the horizontal section and the vertical sections are important elements in evaluating the performance of horizontal wells and provide dynamic data for optimization of reservoir modeling and the determination of long-term economics and ultimate recoverable reserves. However, acquiring quality data in horizontal wells remains a significant challenge. In highly deviated and horizontal wells, production-log job planning, which considers the combination of production logging tool sensors and data analysis methods, is a key factor for obtaining accurate information concerning the behavior of well fluids, formation characteristics, and the extent of well-completion mechanical problems.

The objective of this paper is to share the results of measurements taken from new production logging sensors and analysis methods with production data. These results were used to appraise the efficiency of the tool string by evaluating the acquired data and validating the analysis outputs along with the interpretation conclusions of the production efficiency. The "new-to-the-industry" analysis method consists of integrating multi-probe sensor data, including spinner calibration, superficial-phase velocity calculations, and phase hold-up measurements in a continuous wellbore environment.

While the acquired data has shown valuable information concerning fluid types, fluid compositions, and fluid velocities in these different flow environments, the analysis method has provided a complete integrated interpretation with a more accurate production profile, which is required to properly monitor reservoir performance and diagnose well-production problems.
Efficient Reservoir Simulation Post-Processing
Authors: Frost R. J. , Talbot N. R. , Al-Darrab A. M. , Hajjar O. F.
Published: September 2011

The volumes of data generated by modern reservoir simulators can be huge. This leads to problems with CPU time and memory limitations when presenting the results for analysis. The issue is not just with handling the large arrays for massive 3D grids but also for the well and completion vectors, which can consume many gigabytes of disk space. The problem is compounded by the trend for many simulations of the same reservoir, whether for history matching or to explore multiple development scenarios.

A further issue is with data display. When the number of runs, wells, completions and timesteps gets large, it can be difficult for an engineer to assimilate the information — especially when comparing bulk simulation results with sporadic historical measurements.

This paper describes techniques to overcome these problems. We concentrate on well-related results such as rates and totals, and grid values in completed cells. These include recasting the results into a form suitable for direct access on disk, a load on demand architecture and lightweight in memory representations. In addition user interface ideas that concentrate information are presented.
Thermal-Poro Elastic Stress Effect On Stress Reorientation In Production And Injection Wells
Authors: Abou-Sayed Ahmed S. , Zhai Zongyu
Published: September 2011

Stress reorientation is an important issue for the refracturing design and candidate well design. The long term production/injection causes the stresses to reorient. The temperature differential and pressure differential induced thermal elastic stress and poroelastic stresses are the fundamental reasons for the stress to reorient. A model and numerical scheme are developed to study the effects of thermal differential and pressure differential on stress reorientation. In the model, thermal diffusion and convection is coupled with hydraulic diffusion to obtain the temperature distribution reflecting the cumulative impact. The effective poro-elastic and thermo-elastic stresses are obtained from 1-D displacement equilibrium equation in a radial system. The 3-D in-situ analytical effective stress is superimposed on the 1-D solution. By applying this methodology the 3-D deviated borehole stress model is greatly simplified. The method makes it practical to obtain the stress distribution at any given injection/production time. The thermal stress, poro-elastic stress effects on the stress reorientation are compared and evaluated. Field examples are presented and show that in some cases thermal plays an important role on stress reorientation. The quantified results of the model will give guidance on the fracture treatments and well plan.
NMR Stabilization and Relaxation in a Single Pass Provides Reservoir Solutions
Authors: Smith Charles , Ramakrishna Sandeep , Menendez Eli
Published: September 2011

Conventional reservoir calculations using resistivity and density/neutron porosity have long been the industry standard for defining reservoir characteristics. Calculating water saturation from these measurements is used in virtually every reservoir situation. Many reservoirs have not had straight-forward analysis characteristics, so various and complicated analysis techniques have been applied with varying success through the years.

In some cases, years were spent in characterization before the reservoir was adequately understood. This time and expenditure of resources drained capital from exploration to research processes and, therefore, produced many inefficient completion attempts in reservoirs that were incorrectly characterized as productive.

The great hope with the introduction of NMR tools to the industry was that reservoir answers could be established and used in an uncomplicated manner. Recent advances in technology of NMR responses have produced the ability to capture stabilization time and relaxation time in a single pass through the reservoir. Molecule stabilization time has been demonstrated to have a close relationship to the fluid type in the reservoir. The relaxation time has been characterized to identify fairly precise values of permeability with an excellent relationship to production.

A description of porosity, fluid type, and permeability are established with reasonable accuracy without the need for extensive manipulation of the results. This paper presents examples of logs in sandstone and carbonate reservoirs where this technique is applied. Effective porosity, fluid type, and permeability are all resolved accurately with excellent comparison to production results.
Reducing Safety Incidents While Lifting and Handling Drilling Jars: A Case Study
Authors: Evans Chad D. , Reitsma Rienk , Ramsay Euan
Published: September 2011

The handling of drilling jars can present safety hazards when they are being serviced, transported, loaded or unloaded, handled on the rig floor, run in hole or racked in the derrick. Dangers are especially prevalent if the drilling jar is not equipped with a mechanical locking device. These tools present a potential hazard to personnel because of the possibility of inadvertently activating the jar.

Previously, this issue has been addressed by using an externally installed clamping device which is attached to the jar to lock it open and prevent an unplanned activation. If the clamping device is not properly installed, it can become a dropped object hazard. In response to the potential hazard of a dropped object from the derrick, some drilling contractors have elected to lay out jars from the Bottom Hole Assembly, BHA, on every trip. This in itself adds time to the operation and additional exposure to personnel.

The drilling jar safety clamp has evolved in design and material selection. The industry has evolved to a composite design, which reduces the element of operational error thus reducing the chance of a dropped object in the derrick and improved handling.

The composite design is much more reliable and easier to handle but has failed to eliminate the dropped object hazard. Following extensive risk analysis of the existing clamp, an innovative approach has been conceived in the form of an internal latch mechanism which can eliminate the requirement for an external clamp and provide more effective control of the jar while eliminating a possibility of an object being dropped in the derrick.

In this paper, the authors will review the safety hazards associated with the handling of drilling jars. They will describe the evolution of the external clamp, which is the main device in use. The paper concludes with a detailed discussion of the internal latching device that has been developed in the continuing effort to enhance the safety of drilling operations.
Mitigating Flow Assurance Challenges in Deepwater Fields using Active Heating Methods
Authors: Thant M.M. Myo , Sallehud-Din M.T. Mohd , Hewitt G.F. , Hale C.P. , Quarini G.L.
Published: September 2011

Flow assurance challenges, mainly of hydrates and wax depositions, are amongst the key issues that must be resolved and mitigated to ensure that hydrocarbons can be efficiently and economically transported from well to processing facilities. As wells step further away from shore into deeper water, the flow assurance challenges are increasing tremendously due to prevalence of higher pressure and lower temperature conditions. Thus, the development of cutting edge technologies to cater for the ever increasing demand in exploring the hostile and technologically challenging deepwater fields is a matter of great urgency.

One of the effective solutions to prevent the formation of wax or hydrates is to use active heating methods. This paper describes an overview of the available active heating methods and mechanisms which are being implemented as thermal management systems for flowline in deepwater fields. It also discusses the thermal performance calculation models available to aid the design and modelling of such systems.

Some comparative studies are carried out to determine the advantages and disadvantages of each of the methods to establish a general reference source on the technology that provides the most significant economic impact without compromising the reliability and efficiency of the overall system. Active heating systems have been used in several projects in the North Sea, Gulf of Mexico and Offshore West Africa. This paper also summarizes these projects and their operating experience from open literature.

In general, due to their operational flexibility and high efficiency through control of the pipeline temperature above the hydrate formation and wax deposition temperatures, active heating seems to be the most practical, economical and viable solutions in managing flow assurance issues; especially for the development of deepwater fields.
Evolution of Coiled Tubing Matrix Stimulation for Gas Wells in Saudi Arabia
Authors: Al-Atwi Mohamed , Solares J. Ricardo , Amorocho Ricardo , Garzon Francisco , Kharrat Wassim , Stuker John , Naji Iyad
Published: September 2011

Saudi Aramco has been using coiled tubing (CT) to acid stimulate gas wells completed as single or multiple open hole horizontal laterals in carbonate reservoirs. These CT interventions have evolved from pumping the treatment fluids through normal nozzles, to high-pressure jetting with or without a simultaneous bullheading of inert fluid through CT tubing annulus. Until recently, there was no CT bottom-hole assembly (BHA) available on the market to provide realtime downhole data monitoring during CT acid stimulation. Therefore, these types of stimulation jobs followed a predetermined pumping schedule, assuming that fluids are squeezed at the nozzles depth while reciprocating the CT string from toe to heel. The operator had no means to control the acid coverage across the extended reach open hole laterals.

The bottom-hole pressure (BHP) inside and outside the CT string, monitored real-time with the fiber optic bottom-hole assembly (FOBHA) allows the operator to adjust the differential pressure across the high-pressure jetting tool nozzles. The distributed temperature survey (DTS) recorded with the fiber optic at key stages of the treatment helps identify initial thief zones and any further developing ones during the acid stimulation treatment. Tracking with a DTS, the fluids placement through the high-pressure jetting tool showed that acid was still being injected into thief zones and not squeezed at the nozzles depth. DTS is therefore used to adjust the real-time pumping schedule by deciding when, where, what type and what quantity of diverter to pump to get uniform acid placement across target intervals.

The ability to place stimulation fluids in a highly effective way is the most important element in any successful production enhancement stimulation job. This paper will detail case histories of gas producers in which a fiber optic enabled coiled tubing (FOECT) and a FOBHA were successfully run together to record real-time downhole data in an effort to assess the full stimulation effect of an acid matrix stimulation treatment, and to control and optimize the CT operation.

Several cases demonstrating the effectiveness of the FOECT matrix stimulation technique are highlighted in this paper.
New SEC Rules: What is New for the Petrophysicist?
Authors: Glorioso J. C. , Rattia A.
Published: September 2011

The Securities and Exchange Commission (SEC) of the United States of North America has modernized in December 2008 its regulations for the report of oil and gas reserves. From now on, the oil and gas companies will be able to report reserves of bituminous sands, the economic evaluation of reserves will be made with an yearly average price instead of the price of the last day of the year, the use of (reliable) technology will be allowed to demonstrate the producibility and the (lateral) continuity of production of the reservoirs as well as to determine the fluid contacts. Also, it will be authorized to publish, voluntarily, probable and possible reserves that previously were explicitly prohibited in the SEC reports. One of the important changes that concern to the petrophysicist is the qualification of Reliable Technology to support or demonstrate the producibility of the reservoirs without having a conclusive test. Using technology the petrophysicist will also be involved in fluid contacts determination and in the construction of analogy of the reservoir of interest with other reservoirs at a more advanced stage of development. The use of reliable technology is also enabled to support the estimate of proved undeveloped reserves at greater distances than the development spacing in the field provided that reasonable certainty of the production continuity is obtained by using such technology. The intrinsic technical uncertainty in reserves estimations often makes the estimators to adopt a probabilistic estimate instead of a deterministic one. The use of probabilistic estimates has become frequent in the industry and now the SEC has defined that estimates of proved reserves can be made either deterministically or probabilistically. When a probabilistic estimate is chosen, or when in occasions the petrophysical parameters of an in essence deterministic estimate (net thickness, porosity and saturation of water) are chosen based on a probabilistic approach of the distribution of those parameters, the petrophysicist will have to observe some basic premises to avoid misinterpretations. Also, in the next years, operators and service providers will be embarked in an effort to find new tools and methodologies for reservoir evaluation and reserves estimation that allow them to value their properties with reasonable certainty still at the early stages of development. This will take place under a modernized regulatory framework that will enable the use of the most modern technologies provided that they can offer consistent, repetitive, and reasonably certain results on the expected answer of the reservoir.
Field Application of Chemically Treated Substrate in Pre-packed Well Screen
Authors: Weirich John B. , Monroe Terry D. , Beall Brian B. , Singh Amit Kumar , Gupta D. V. , McBee Jim
Published: September 2011

Chemically impregnated substrates have been successfully used for several years in fracture treatments to achieve long-term inhibition of downhole scale and other precipitates. These solid chemical treatments are gaining wider interest in non-fracture applications. The well designer is challenged to place the substrate in the production flow stream, so as to effectively treat the produced fluid, while at the same time ensuring the integrity of the completion as a whole. The application of a pre-packed well screen to convey the impregnated substrate in a gravel packed well is discussed as well as the evaluations made of the substrate’s fines plugging tendencies and the design of the pre-packed screen itself. The work conducted indicates that correctly sizing the substrate in relation to the gravel pack proppant and designing a special, enlarged pre-packed screen can ensure effective delivery of these chemical treatments in a variety of well completions.
Smart WaterFlooding for Carbonate Reservoirs: Salinity and Role of Ions
Authors: Yousef Ali A. , Al-Saleh Salah , Al-Jawfi Mohammed
Published: September 2011

The salinity level of injection water in the past has not been considered as a key parameter in oil recovery from water-flooded reservoirs. In the recent years, extensive research on oil/brine/rock systems has shown that injection low salinity brines has a significant impact on the amount of oil recovered. Although, the potential for carbonates has not been thoroughly investigated, some reported studies have excluded carbonates from this effect.

Saudi Aramco through its upstream research arm (the Advanced Research Center) has initiated a strategic research program tagged "Smart WaterFlood" to explore the potential of increasing oil recovery by tuning the injection water properties. Based on the research work for the last three years, we demonstrated in a previous report (SPE 137634) that substantial oil recovery beyond conventional waterflooding from carbonates can be achieved by optimizing the salinity and ionic composition of field injection brine. Also, research confirmed that the driving mechanism is wettability alteration of carbonate rock surface.

This paper highlights extensive and a broad range of laboratory studies including wettability and surface chemistry studies to define the role of water ions in the induced wettability alteration, which is crucial in determining the optimum composition of injection water for future field applications.

The rock surface chemistry studies pointed out the potential mechanisms for wettability alteration triggered by injecting different salinity slugs of field injection water. The contact angle results indicated that a sufficient reduction in the ionic strength of field injection water is required to trigger the effect of wettability alteration. All evidence gathered during this research work indicate that what we deal with in this study is a new research trend, different from what have been addressed in the literature on low salinity waterflooding for sandstones, and seawater injection in chalks.
Accounting For Adsorbed Gas in Shale Gas Reservoirs
Authors: Mengal Salman A. , Wattenbarger R. A.
Published: September 2011

Shale gas reservoirs have become a major source of energy in the recent years. Developments in hydraulic fracturing technology have made these reservoirs more accessible and productive. Apart from other dissimilarities from conventional gas reservoirs, one major difference is that a considerable amount of gas produced from these reservoirs comes from desorption. Therefore it is important to understand the adsorption phenomenon and to include desorbed gas and its effect in our analysis.

The objective of this work was to imbed the adsorbed gas in the techniques used previously for the analysis of tight gas reservoirs. Most of the desorption from Shale gas reservoirs takes place in later time when there is considerable depletion of free gas and the well is undergoing boundary dominated flow (BDF). For that matter (BDF) methods and utilizing end of transient time, to estimate OGIP, that are presented in previous literature are reviewed to include adsorbed gas in them. (Kings (1990) modified z* and (Bumb and McKee’s (1988) adsorption compressibility factor for adsorbed gas are used in this work to include adsorption in the BDF and end of transient time methods.

Employing a mass balance, including adsorbed gas, and the productivity index equation for BDF a procedure is presented to analyze the decline trend when adsorbed gas is included. This procedure was programmed in EXCEL VBA named as Shale gas PSS with adsorption (SGPA). SGPA is used for field data analysis to show the contribution of adsorbed gas during the life of the well and to apply OGIP estimation methods with and without adsorbed gas. The estimated OGIP’s were than used to forecast future performance of wells with and without adsorption.

Original gas in place (OGIP) estimation methods when applied on field data from selected wells showed that inclusion of adsorbed gas resulted in approximately 30% increase in OGIP estimates and 17% decrease in recovery factor (RF) estimates. This work also demonstrates that including adsorbed gas results in approximately 5% less stimulated reservoir volume estimate.
Single-well In-situ Measure of Oil Saturation Remaining in Carbonate after an EOR Chemical Flood
Authors: Edwards John , Ramamoorthy Raghu , Harrigan Ed , Singh Maniesh , Soek Harry , Van Wunnik John , Al Yarabi Mohammed , Al Mjeni Rifaat
Published: September 2011

The MicroPilot* is a log-drill-inject-log sequence of operations designed to evaluate the improvement in oil recovery resulting from the addition of chemicals to the injected water. The fluid to be injected is transported downhole in a sample chamber and injected into the formation through a pencil sized drilled hole, with measurements of the resulting changes in saturation proximal to the well. This technique was first used during 2009 in Oman to perform an in-situ test of alkaline surfactant polymer in high porosity-permeability clean sandstone saturated in medium viscosity oil.

This in-situ measurement is even more relevant for carbonates, as it eliminates the uncertainty associated with restoring mixed wettability in cores prior to laboratory enhanced oil recovery (EOR) floods. However executing a log-drill-inject-log sequence of operations in tight carbonates is more complex than clastics. The issues include small scale heterogeneity, presence of natural or induced micro-fractures, varying residual oil saturations, and the low permeability that requires injecting at pressures above the drilling fluid hydrostatic pressure.

The operation and results of the first use of this EOR screening technology in carbonates is described in this paper in which an alkaline surfactant mixture (AS) was injected into a partially water swept 3mD permeability carbonate containing light oil. Aspects described include the mechanical process of drilling and injecting AS and the petrophysics of measuring changes of oil saturation at a small scale. The saturation changes are compared with other AS flood measurements in a neighboring well test using Single Well Chemical Tracer (SWCT) and cased hole logs.

*Mark of Schlumberger
Long-Term Injectivity Test in a Field Characterized by a Tar Mat Zone Strives to Unlock Higher Reservoir Potential
Authors: Arukhe James O. , Al Dhufairi Mubarak , Al Ghamdi Saleh , Harbi Badr , Docherty Paul R.
Published: September 2011

A carbonate field in Saudi Arabia is undergoing major development requiring water injection wells to provide peripheral matrix water injection as pressure maintenance to support oil production. The field is characterized by a tar mat zone, which potentially could isolate the oil reservoir from the planned pressure support and serve as a barrier for the water injection. Therefore, the injection wells were geosteered horizontally right above the tar "barrier" into the transition zone between the heavy and lighter oil, which poses a challenge in assuring adequate pressure support to the producers, without leaving pockets of relatively high oil saturation behind the waterflood front.

To address transmissibility uncertainty between producers and the injectors, long-term injection (LTI) pilot tests were designed utilizing one water injector and six observation wells to capture pressure signals. Building the surface facility to deliver the required test as planned was challenging, starting with the seawater as a source, to the water treatment and ending with pump selection. This paper discusses the unique layout of the LTI surface equipment, a mini-plant by itself, and how operational challenges were overcome in the field. The authors highlight some operational issues related to the LTI test that had almost 90% efficiency from operating over 200 days and over 2 million barrels of injected filtered and treated seawater volume, as well as presents valuable insights to demonstrate how a project of this scale was successfully executed and more value added to the development plans.

The unique equipment layout is composed of twin sea-submerged, skid-mounted electrical submersible pumps (ESPs), 6″ hoses, filtration unit, a chemical treatment unit, eight 500 bbl storage tanks, and a horizontal pumping system (HPS). The layout of the surface facility components, their performance and the importance of continuous water injection in addressing the test goals are discussed. The injection well performance was monitored by integrating Joshi’s equation to Hall Plot and slope analyses to pr ovide means of more meaningful use of injection pressure and rate data. The synergy of the mini-plant components coupled with engineered performance monitoring tools were enablers in this test design to help unlock more reserves. Overall, the test was a great tool to qualify field development plan assumptions, indicating that less powered water injectors than initially planned are required.
The Potential Pitfalls of Using North American Tight and Shale Gas Development Techniques in the North African and Middle Eastern Environments
Authors: Martin A. N. , Eid R.
Published: September 2011

Many companies operating in the upstream gas industry in the Middle East and North Africa (MENA) are interested in the outstanding successes achieved by the US and Canadian tight and shale gas producers. It seems almost miraculous that companies can obtain economic gas production rates from rocks with permeabilities measured in nanodarcies – so low, in fact, that it becomes almost impossible to accurately assess. Operators in MENA, who are accustomed to working in formations with permeabilities 5 or 6 orders of magnitude greater, have recently realised that they may be sitting on top of huge untapped gas reserves that had previously been evaluated as sub-economic.

In recent years, several major MENA-based operating companies have bought interests in US and Canadian tight and shale gas operations, with the objective of acquiring experience and technology that can be applied to similar formations in MENA and elsewhere. This seems to be an obvious and wise strategy; unfortunately, the problem is not the strategy, it is the tactics ("the devil is in the details"). In many instances, operating companies have been disappointed to discover that they cannot simply transplant an American-style development into MENA. Similarly, many North American independents have viewed the untapped low-permeability gas reserves of MENA as a natural territory for expansion, only to find themselves frustrated at almost every turn.

This paper seeks to highlight the potential pitfalls of trying to use North American development techniques in MENA and to promote strategies and tactics that are more suitable. In addition, this paper will suggest structural changes that could have a significant positive impact on low-permeability gas developments in MENA.
Automating Well Performance Monitoring of Real Time Data
Authors: Al Nuaim Ahmed , Williamson Mike , Hasan Sualeh , Holdaway Keith , Krug Steffen , Labban Marwan M.
Published: September 2011

Estimating reserves and predicting production in reservoirs has long been a challenge. The importance of performing accurate analysis and interpretation of reservoir behavior using only rate and pressure data as a function of time or cumulative production is fundamental to assessing remaining reserves and for forecasting production. An interactive system was developed to assist in Decline Curve Analysis (Cartesian, Exponential, Harmonic and Hyperbolic) and Production Forecast in an Integrated Reservoir Management environment.

Different techniques are often applied in short and long term production forecasting. The associated uncertainties are of a different nature for the various time scales. The handling of these uncertainties has proven to be highly challenging for most oil and gas companies. There are tendencies to underestimate uncertainty and completely fail to account for "unforeseen" events which can erode the forecasts.

Adopting a methodology of advanced analysis of production decline curves provides important forecasting results for future production from a single well or multiple wells across reservoirs and fields. The amount of data to be analyzed must be managed and aggregated efficiently. It is imperative to ensure the data are robust and thus have been explored via workflows based on advanced analytics to remove outliers and provide spatially viable input parameter values.

This paper introduces a refreshingly intuitive navigation of the disparate data sources and input parameters aligned with a comprehensive suite of forecasting models wrapped into a web-based solution. The user is enabled with interactive graphical output to extensive "what-if" combinations of critical input parameters across multiple forecasting models. Whether working with oil or gas reservoirs, the user has access to a rich compendium of forecasting techniques that detail accuracy indicators and interactive graphs. The relationship, for example, between p/z and cumulative gas production for typical gas reservoirs can be studied by calculating pressure response to various modes of gas production and water encroachment. Water encroachment methods considered are Schilthuis, Hurst simplified and van Everdingen-Hurst.
Laboratory Investigation of Low Salinity Waterflooding on Reservoir Rock Samples from the Frøy Field
Authors: Hadia Nanji , Lehne Håvard Heldal , Kumar Kanwar G. , Selboe Kristoffer , Stensen Jan Åge , Torsæter Ole
Published: September 2011

Laboratory studies of low salinity waterflooding (LSW) have been performed to evaluate the potential of improved oil recovery at the Frøy field. Coreflooding experiments were conducted at high temperature and low pressure on reservoir core samples to determine the potential of LSW as an enhanced oil recovery (EOR) process for the field. Experiments were performed on several core plugs selected from two different wells at different depths of the reservoir. Synthetic formation brine and Frøy crude oil were used in the experiments. The injection brines of three different salinities were prepared synthetically by diluting the high salinity brine with deionized water. X-ray diffraction (XRD) analysis, computed tomography (CT) scans and thin section analyses were also carried out to study the mineralogy of the reservoir. The results showed an incremental recovery from 6 to 14 % of original oil in place for low salinity waterflooding. The residual oil saturations were reduced by 4 to 9 % of pore volume at the core scale. A significant reduction in permeability of the core plugs was also observed. It was also observed that the core permeability decreased more significantly with the increase in clay content as a consequence of LSW. The experimental results showed a possible EOR potential of LSW for the investigated formation of the Frøy field.
H2S Challenges Presented to ESP Systems
Authors: Sikes M. A. , Adams D. L. , Qi J. P. , Wonitoy K.
Published: September 2011

Hydrogen sulfide (H2S) can negatively impact electrical submersible pumping (ESP) system reliability through several mechanisms, including the increased probability of corrosion, promotion of iron sulfide (FeS) formation, and initiation of sulfide stress cracking (SSC). H2S is a naturally-occurring chemical compound in wellbores throughout the world. The presence of H2S can result in various forms of corrosion that attack ESP systems, causing premature failure that results in lost production. ESPs have shown to be good candidates for wells with H2S concentrations up to 40%. Bottomhole temperatures (BHT) of 325° F with measurable amounts of H2S have also had positive results.

H2S reacts with wellbore fluids to create free hydrogen resulting in hydrogen embrittlement potential. Additionally, the free sulfur can lead to SSC in high-strength steels over time. H2S can also react with H2O and form sulfuric acid (H2SO4) or free sulfur. This is an additional source of corrosion that the ESP can experience, resulting in corrosion or fatigue of the system.

Using application guidelines, H2S-resistant materials can be used in various configurations depending on the H2S quantity and the BHT, allowing for the best combination of defense while considering the overall system. High-strength shafting and corrosion-resistant couplings, fasteners, and housings offer the most protection from corrosive elements.

Cable and motor lead extensions (MLE) benefit from the application of lead barrier protection. Lead is a stable element that is dense and malleable, offering excellent corrosion protection to the electrical system. All of these combinations enable an operator to increase reliability of the ESP even when exposed to highly corrosive environments. Finding a balance between specialized materials with varied H2S resistance ability enables different levels of H2S prevention to be offered, depending on the concentrations seen.
Reserves Management System - Rapid Tool for Optimizing and Tracking the Growth of Hydrocarbon Resources & Reserves
Authors: AlBahar Mohammad , Kamal Dawood , AlMayyan Haya , Bora Anup
Published: September 2011

Kuwait’s resources and reserves to date are characterized by giant, large, massive oil and gas fields located in onshore and offshore areas of Kuwait. These fields are under different stages of development like natural depletion, pressure maintenance and enhance oil recovery (EOR) processes. Over the years, huge amount of resources and reserves data has been accumulated from these fields. This has made Kuwait Oil Company (KOC) to re-evaluate its approaches towards management of these huge volumes of data efficiently. With passage of time, it has become more challenging to manage these reserves and resources volumes and promotions to meet company’s growth strategies.

Historically, KOC was managing its resources and reserves through a manual Reserves Management System (RMS) spreadsheets for tracking, archiving, monitoring, reporting and managing the resources and reserves.With time, RMS has become a very complex and involved process and it was felt necessary to introduce a new process and tool to manage the overall RMS workflow efficiently to meet company’s business needs. Accordingly, KOC decided to introduce a systematic workflow tool to streamline the process of managing hydrocarbon resources and reserves data. The new workflow process consist of a robust multiusers database for archiving, managing and reporting which can be accessed by different teams at different security levels. This enhanced system enabled KOC’s management and reserves evaluators to optimize the company’s resources and identifying possible opportunities to meets its strategic goals.
Effect of Surfactants on Water Imbibition into Heterogeneous Carbonate Rocks at an Elevated Temperature
Authors: Han Ming , Fuseni Alhasan B. , Yousef Ali A. , Kokal Sunil L. , Al-Saleh Salah
Published: September 2011

Spontaneous imbibition of water into water-wet reservoirs has a positive effect on oil displacement and recovery. For carbonate reservoirs which are generally neutral to preferential oil-wet, surfactants may be used to alter wettability towards water-wet that assists water imbibition and consequently oil recovery. Depending on the surfactants selected, oil recovery can be significantly improved for carbonate reservoirs. This paper presents the results from a laboratory study on improved spontaneous imbibition of water into oil saturated carbonate rocks using surfactants. Three kinds of surfactants and one surfactant/polymer formulation were selected and evaluated in terms of compatibility with field brines, critical micelle concentration, interfacial tension, contact angle, and viscosity. The imbibition experiments were performed at 75°C to investigate oil recovery potential and the impact of interfacial tension, wettability, and viscosity. The results show that the addition of the surfactants can significantly oil recovery in the secondary oil recovery mode, compared to the imbibition process of water alone. Similar oil recoveries were observed when surfactant was used alone or mixed with a polymer. In tertiary oil recovery mode, low interfacial tension fluid showed a greater incremental oil recovery. This paper provides insights on selection and utilization of chemicals in increasing oil recovery from carbonate reservoirs, based on imbibition experiments.
Measuring the Performance of Corrosion Inhibitors to Prevent Black Powder Formation Using a Novel Quartz Crystal Microbalance Technique
Authors: Jovancicevic Vladimir , Ramachandran Sunder , Cattanach Kyle , Sherik Abdelmounam
Published: September 2011

Black powder formation is an oxidative corrosion process that over time can cause operational problems as the solids collect within the system. There is a net weight gain within the system as molecular oxygen becomes incorporated as part of the solid materials. A novel quartz crystal microbalance (QCM) test apparatus has been developed to determine the effectiveness of various corrosion inhibitors to prevent black powder formation in sales gas pipelines. The QCM measures minute changes in frequency of a quartz crystal with weight gain/loss. For our test apparatus, the QCM crystal was coated with iron where small increases in mass due to oxidation of the iron layer were recorded as a drop in frequency. Using the Sauerbrey equation, the drop in frequency observed during corrosion testing can be converted to a corrosion rate. Several inhibitor chemistries were tested using the QCM apparatus. In this study it was found that a new oil-soluble corrosion inhibitor is the most effective for preventing black powder formation under the sales gas conditions.
Monobore Expandable Liner Extension Deployment Saves Well From Abandonment
Authors: Stockmeyer Carl F. , Durment Albert S. , Ismail Ahmed , Lapeira Manuel
Published: September 2011

Caving, sloughing, and swelling shale sections, combined with lost returns below 13-3/8-in. casing, were encountered in an Egyptian well. Before the 12.25-in. hole section was completed, shales packed off the drillstring and part of the bottomhole assembly (BHA) was left in the hole. Casing (9-5/8-in.) was run as deep as hole conditions allowed, with a recess shoe to enable a monobore expandable liner extension. Following drillout of the shoe, conditions presented the same challenges previously experienced. The 8-in.outside diamer (OD) liner extension system was run, but well conditions prevented getting the liner to depth and it was pulled out of the hole.

Conditioning trips with increased mud weight up to 12.3 pounds per gallon (ppg), reaming and backreaming, along with an open hole cementing effort, were performed for stabilization. A second attempt was made to run in the hole. The hanger located in the recess shoe profile of the 9-5/8-in. casing and the system was expanded to the same inside diameter as the casing above. The expanded liner’s shoe was now located just above the previously left BHA, but the trouble zone sections were isolated with no reduction in hole size from the previous casing.

The expanded liner was pressure tested to 1,000 psi before cementing. Recess shoe ports were enabled and initial circulation established, and the wellbore did indeed pack off and build pressure, preventing full annular cement. Pressure inside the casing was applied and 15 barrels (bbl) of cement were squeezed into the hole. A casing exit was milled in the expanded monobore liner to enable bypassing the BHA that was left in the hole from previous drilling operations.

The case history explored in this paper highlights overcoming substantial issues using expandable drilling liner technology via a monobore liner extension that resulted in successful installation and circulation. The preplanning, installation considerations, expansion process, lessons learned and post-deployment results will be discussed.
A Unique Stimulation Approach to Enhance Production Efficiency of Horizontal Wells in Heterogeneous Carbonate Reservoirs
Authors: Fahim Mohamed , Keshka Ashraf , Marzooqi Ayesha Al , Assreti Elamari , Helmy Hamdy , Salim Dalia , Neyaei Fardin Ali , Rafieenia Marzieh , Hudson Lisa
Published: September 2011

Matrix stimulation treatments are applied to improve well productivity and enhance the hydrocarbon recovery from the formation. However, in some wells optimum results cannot be achieved using conventional stimulation techniques since it is difficult to ensure efficient placement of the stimulation fluid across the entire stimulation interval. This is a prerequisite for a successful result. The situation becomes even more challenging in heterogeneous reservoirs with large permeability variations or possible presence of natural fractures in a complex geological environment.

Other complications may occur when conventional stimulation treatments keeps creating undesired wormholes throughout the same spot within existing (horizontal) bore hole. These complications may result in making future diversion jobs even more challenging and sometimes enlarges the hole to the limit of affecting accessibility in future interventions.

The paper describes a unique approach that has been successfully executed in one of the super giant onshore fields in Abu Dhabi through an extensive study over different types of heterogeneous reservoirs. The objective was to develop an economically justified stimulation strategy utilizing different treatment fluids and a unique placement approach which led to proper reservoir drainage. In this field the production comes from various carbonate reservoirs, where the different layers are subject to different methodologies to support the reservoir pressure. The approach consists of chemical diversion, dual injection for acid placement, and optimized jetting tool.

The paper also describes the results of re-stimulation of a group of wells as part of field pilot. Actual data from several treated horizontal wells are presented. The methodology of candidate selection, treatment design and execution is described along with pre and post stimulation production logging.

The paper highlights the impact of production improvements of the treated wells. Chemical diversion, as proved in the pilot wells, enhanced the acid stimulation. It was shown that previously untreated subunits, were now contributing to flow. The pilot wells have validated the engineered methodology adopted for the work-scope.