bluuebunny/crossref_metadata_2025 huggingface dataset:
Brownfield Facilities Upgrading for ESPs
Authors: Salim Muzahidin M , Saenz Dan , Pattay Patrick , Symic Ryan , Anang Nazaruddin
Published: February 2010

Electrical Submersible Pumps (ESP) are commonly employed in brownfield wells where watercut has increased and gas lift is no longer an efficient production strategy. Much attention is rightly paid to the impact this strategy will have on the reservoir and careful planning is given to the workover operation. However, often the challenge of implementing ESPs is not below the wellhead, but at the facilities level.

One such example is the Bokor Field offshore Sarawak where, in 2008, the first production ESPs in Malaysia were installed. Initially, an in-depth power study was performed. A holistic plan was then developed to distribute the available power to the ESPs via the existing electrical infrastructure. Various locations were considered for the placement of ESP control equipment and ultimately the project team chose a location near to the wellheads. This choice of location required less structural re-design but did involve laying a subsea cable for power transmission and consideration of IP Area Classification Codes for Installations Handling Flammable Fluids.

The ESP power and control equipment was installed inside a customized Local Electrical Room (LER) and, because of space constraints, small deck extensions were required. Safety systems such as fire and gas detectors and individual well sensors for downhole status and flowline pressure monitoring were also included. The electrical systems were tied into the wellhead control panel to allow for automatic process and emergency shutdown actuation. Finally, the surveillance system needed upgrading to incorporate these sensors and allow remote operation since the object platforms were to remain unmanned.

For the Bokor field, the preparation of facilities for ESPs ultimately became its own project much larger and more complex than the workovers themselves. A field designed for gas lift with minimal power needs was successfully transformed to increase and efficiently distribute power along with allowing safe, remote pump operation and surveillance.
Advanced Horizontal Well Model
Authors: Kuznetsov D. S. , Cheremisin A. N. , Chesnokov A. A. , Golovin S. V.
Published: February 2010

A new semi-analytical model developed allows making fast modeling of the heterogeneous reservoirs, drained by a single horizontal well with multiple transverse hydraulic fractures. It is assumed that: –the flow in the reservoir obeys Darcy law;–the fluid contains only one phase;–the reservoir permeability tensor is a function of the variable, directed along the horizontal wellbore;–the well trajectory is not a straight line;–the wellbore has finite conductivity

The proposed model is fast in terms of the execution time and the time required to build a new case.

In the first section of this article a description of the solution method is given.

The second part is dedicated to validating the proposed model. The recognized finite-difference hydrodynamic simulator (FDS) was used as reference software, though fhe model and FDS are not competitors because of their differing applicability. For this reason the execution times of the FDS and the Advanced Horizontal Well (AHW) model are not compared with one another. More significant is that using this model one can generate a new case in fifteen minutes even when the properties of the reservoir are complex and when there are multiple fractures.

The primary focus of the AHW model is a single well productivity index analysis, and candidate selection for stimulation.
Hydraulic Fracturing Makes the Difference: New Life for Old Fields
Authors: Martin A. N. , Rylance M..
Published: February 2010

An increasing percentage of worldwide hydrocarbon production is being achieved from mature fields, as new discoveries prove elusive and technically challenging to bring to market. In this environment, robust and efficient enhanced recovery from these mature assets will play an increasingly important role in production operations. Often used as an initial completion approach or selective remedial stimulation method, hydraulic fracturing is increasingly applied as the method of choice to bolster and improve such declining fields to restore and maintain higher production levels.

Hydraulic fracturing is finding increasing application as a widespread approach to mature field redevelopment. This paper will explore the various factors that should be considered when proposing hydraulic fracturing for this purpose, given the very specific nature and condition of mature fields.

Techniques that can be applied to determine various aspects of mature field fracturing operations will be discussed, together with approaches related to all areas of fracturing implementation; this will provide the reader with an ability to perform a first-pass assessment of the pros and cons of various approaches. In addition, there will be significant discussion related to the potential pitfalls associated with ill-prepared and inappropriate campaigns.

Case histories will provided examples of mature field redevelopment utilising hydraulic fracturing as the principal approach. Candidate selection and pre- and post-frac production behaviour will be discussed, together with the lessons learned and improvements realised during the execution of these programmes.
North Africa Case Histories of a New Wireline Logging Method for Determination of Free Point to Assist Pipe Recovery Operations
Authors: Kessler Calvin , Weiser Jerry , Hill Jim
Published: February 2010

The identification of the free point in drill collars, drillpipe, tubing, or casing is critical for successful drilling recovery or abandonment operations. A new logging tool, available in the wireline service sector, has been developed and field tested that will help to cost-effectively identify a free point. The tool uses the property of steel called the magnetostrictive effect. When stress is applied to steel, the magnetization of the steel is modified. The procedure using the new tool requires two logging passes. The first logging pass records magnetization information about the pipe with the pipe in a neutral weight condition. The second logging pass records magnetization information with tension or torque applied to the pipe. When torque or tension is applied to pipe that can be stretched or torqued, its magnetostrictive properties change. If a section of the pipe cannot be stretched or torqued, magnetization effects remain unchanged. On this basis, the free point (the transition from pipe that can be stretched or torqued to pipe that cannot) is easily detected by comparing two logging passes. Previous free point determination methods required a series of stationary measurements with the pipe in a neutral weight condition, the application of stretch or torque, and the presence of a highly skilled pipe recovery expert on location. The new method simply involves an overlay of two logging passes before and after the pipe has been stretched or torqued. The tool has been successfully tested in steel alloys with minimal magnetic properties.

This new logging tool has significant advantages. First, from a safety standpoint, the application of pipe stretch is applied for only a few minutes between logging passes, whereas legacy methods required numerous station measurements with the pipe being stretched. Secondly, because the determination of a free point requires a comparison of logging passes, real-time operations with constant satellite communications readily permits remotely-based operator and service company pipe recovery experts to be involved with plans for freeing the pipe. The new technology is independent of a highly skilled on-site pipe recovery expert and the delays associated with waiting for the expert to arrive on location.

The tool is small in diameter, run centralized, and does not require weight bars added to the tool for slip engagement. These features shorten the length of the tool string and simplify e-line rig-up procedures. The short tool length has advantages in deviated well conditions in which pump down free point tool deployment may be required.
Detailed Compositional Modeling of Gas Injection Pilot in Giant Carbonate Reservoir in the Middle East
Authors: Obeida Tawfiq , Gibson Adrian , Al-Hashemi Hussain , Baruah Bikram
Published: February 2010

The objective of this paper is to address the challenges that are frequently encountered in simulation studies when using local grid refine (LGR) within upscaled models. The difficulties mainly arise due to the unreliability of populating the fine grids with reservoir properties and attributes.

Dynamic modeling of a pilot is an important task to predict fluid flow and reservoir behavior which is a major step of pilot design. Dynamic models usually have many limitations when it comes to geological description due to the upscaling of fine-grid static model. Using local grid refinement (LGR) alone for the pilot area within a coarse dynamic model also would not enhance reservoir description of the pilot area without a realistic reservoir description. This work was aimed to provide an improved method for the proper simulation of pilot project in order to optimize the design of the pilot injector, borehole location and length. Furthermore, the model would be used to plan an efficient reservoir monitoring program including an optimized well data gathering with sponge coring for defining the remaining oil saturation.

To overcome these limitations, the proposed method introduces a special fine scale LGR covering the pilot area within the upscaled dynamic model. Whereas the upscaled model has 36 layers, the LGR contains exactly the same fine-scale layering scheme and reservoir properties as the static model with 160 layers. Thus, it eliminates the upscaling process within the LGR. This process will ensure a better quality history match, for example the TDTs and RSTs derived saturations when compared against the fine layer LGR from the dynamic model.

The dynamic model in this study is a large sector model (Nx 167, Ny 98 and Nz 36) with a detailed LGR (Nx 130, Ny 145 and Nz 160). The fluid properties were calculated from a 10-components equation of state (EOS). After the addition of the LGR, the model history match was updated. Several prediction cases were then studied to optimize well location (injector and observation wells) in order to convert the existing inverted five-spot gas pattern into water injection line-drive. Several saturation maps and profiles were generated to predict the breakthrough time for each observer and utilized to design the future pilot monitoring program. The new data will be utilized for future updates of the history match and performance of pilot under the optimum scheme of sweep and thus well spacing.
Embedded Knowledge-Management Systems Increase Cost Efficiency of an Organization: A Case Study
Authors: Jaripatke Omkar , McElroy Monty
Published: February 2010

In the global marketplace, considering the bleak outlook for the economy, successful companies must tailor their business model to continually increase efficiency for proven revenue-generating processes by reducing costs associated within operations, technology, manufacturing, and logistics. Focusing on economics can never be detrimental to health, safety, and operational-efficiency standards, which remain at the forefront for all operations. A knowledgeable and competent workforce is necessary to sustain efficient "cost-savings driven" operations. Knowledge-management systems (KMS) and concepts are tools that integrate divisions or units within a corporation effectively to achieve the business goals and shared vision of the corporation as a whole.

Much has been written on the knowledge-management (KM) concept, but most of it discusses in detail only the concept and vision. This paper discusses the KM concept model, challenges, and the successful integration and implementation of KM in a company. This includes where KM communities have been implemented in each major product-service line (PSL) of the company and in support-position job functions where knowledge workers service multiple PSLs. It discusses how the scope of the KM teams has expanded from the original intent to how the KM portals are involved in diverse projects on a daily basis to bring together different ideologies and functionalities within a company to achieve the business objectives discussed above. In addition, it discusses the future vision for KM within a large multinational service company to share and embed collaborative concepts weaved into the fabric of the company by networking people throughout the whole organization.

The book on KM within the energy industry is still being written; it is a work in progress, virtual, and the editing is ongoing.
Dynamic Behavior of a Fissured Dual-Carbonate Reservoir Modeled with DFN
Authors: Akram A. H. , Gherryo Y. S. , Ali S. M. , Thabt M. S. , Serban A..
Published: February 2010

A Paleocene dolomite in northeastern Libya was modeled using three porosity types: matrix porosity (intercrystalline plus the separate vugs), horizontal-to-subhorizontal solution-enlarged vuggy porosity generated by dissolution and named "touching vugs," and fracture porosity.

The touching vugs, which acted like fractures in their dynamic behavior, are modeled as a very permeable discrete fracture network (DFN) in PETREL* seismic-to-simulation software. Their presence is known primarily due to pressure buildup analysis, and it is expected that they would be interconnected over hundreds of meters.

The primary challenge in dual-media modeling is being able to characterize and predict the dynamic behavior of the complex matrix + fracture + touching vug system. There are three wells in this area of northeastern Libya with pressure buildups that have an unusually distinct and pronounced dual-porosity signature. Each well has been matched by adjusting the five primary parameters: matrix and fracture porosity and permeability, and the sigma shape factor. Aquifer strength also had to be adjusted.

There are some aspects of the dynamic behavior of this reservoir that are of particular interest: The highly fractured low-porosity parts of the reservoir are the least productive, and the least fractured high-porosity parts with touching vugs are the most productive.The well test shows pronounced dual-porosity behavior and indicates a high level of contrast between the matrix and secondary porosity systems, both in terms of permeability and porosity.There is a strong aquifer and in reservoirs with moderate fracture permeability, we would expect to see the fractures provide a pathway for rapid water breakthrough. Owing to the very high permeability associated with the fracture system, this does not happen as expected; i.e., the reservoir acts to some extent like a tank with a level oil/water contact (OWC). There is not much coning or advancing of water in the secondary porosity system.

This paper presents the dynamic features of the reservoir and demonstrates how the simulation model was calibrated using all available information, in particular, the pressure buildups.
Gravity Data Analysis and Interpretation of Sirt Basin, Libya
Authors: Saheel Ahmed , Bin Samsudin Abdul Rahim , Bin Hamzah Umar
Published: February 2010

The produced Bouguer gravity map shows prominent NW-SE and N-NW trends.

Total horizontal derivative gravity map of the study area shows strong horizontal gradient anomalies that are located in eastern and central parts of the area. The central part of the basin can be divided into four zones the eastern zone shows many short anomalies of NW-SE orientation; the southern zone shows N-S orientation; the northern zone shows NW-SE orientation trends; in the western zone strong NW-SE trends cut with NE-SW changing to E-W trends. Isostatic residual map is characterized by a dominant northwest – southeast trend in the study area. This is clearly evident in the isostatic residual. The main trending anomalies are in the northern and southeastern parts of the study area with NW-SE orientation. A strong NW-SE trend is truncated by E-W trending in the southeastern and southwestern parts of the area. This is consistent with change of tectonic zones.
Open-Hole Solid Expandables Eliminate Slim-Hole Configuration in Integrated Solution Workover Well
Authors: Farhat Ali , Zeghouani Rabah , Sanders Tom , Saad Marc Antoine , Roushdy Marwan
Published: February 2010

In Algeria about 60% of the proven oil reserves are in the Hassi Messaoud region which was discovered in the 1950's. Several oil production wells drilled over 40 years ago have been shut in and are awaiting workover plans to revive those wells and get them back into economic production. A typical workover program is comprised of extending the open-hole in the reservoir zone, below 7-inch casing, and producing that through a new 4-1/2-inch perforated production liner. At the time of initial drilling of those wells, the reservoir pressure was as high as that of the shale zone immediately above it. This reservoir pressure has now declined and can be found to be as low as one-third of the shale formation pressure.

This recent variation in formation pressures (between exposed shale and reservoir zones) has created a need to mechanically isolate this exposed shale zone immediately above the lower pressure reservoir prior to drilling ahead. Original workover programs required the use of an additional (smaller size) casing string for this purpose, with the eventuality of drilling the reservoir open-hole section with a much smaller hole-size and completing the well as with a slim-hole configuration.

This paper presents an alternative solution that was implemented to workover these type of wells and enable completion with a sufficient hole-size in the producing zone to avoid a slim-well configuration. The major technology used to facilitate this alternative workover was the installation of a solid expandable open-hole liner to mechanically isolate the high pressured shale zone above the reservoir. The aim was to still allow for a large enough open-hole passage in to the reservoir section to facilitate the use of high performance directional drilling BHA assemblies,

The overall application of this workover is discussed to detail and highlight the added-value solid expandable liners provide in such workover applications. The successful integration and planning of the solid expandable installation along with; short radius casing exit, zonal isolation, and enhanced directional drilling has proven to be a significantly superior technical and economic alternative solution.
Reservoir Simulation Explains Production Problems in Nile Delta Gas Field
Authors: El Sheriff Hossam , Reda Mohamed , Gonzalez Christine , Hassouba Almoataz Bellah , Abd El Hady Ahmed , Sidky Mahmoud
Published: February 2010

This paper provides a case study of how detailed reservoir modeling and simulation helped to explain existing production problems and to subsequently optimize reservoir management for a gas field in the Nile Delta. In this example the complex geology of a fluvial deltaic system was modeled using the concepts of sequence stratigraphy to build the basic reservoir architecture for the Abu Madi Formation. Then seismic attributes were used to characterize the detailed facies and permeability distribution and the interplay of sands and shale in the reservoir intervals. This allowed a representative three dimensional reservoir simulation model to be built that could more accurately reproduce the water influx and gas water contact movement that had happened in the reservoir as a result of historical production conditions. In addition it confirmed that the different reservoir intervals had different reservoir drive mechanisms and thus needed to be managed differently. This was not fully understood using conventional techniques due to the relatively low well density.

This paper will include the specific lessons learnt for three gas wells in a small Upper Abu Madi fluvial channel in the Nile Delta Field where production conditions caused rapid water influx, water production from coning and gas blocking between wells which was not recognized without the detailed geological and dynamic understanding. In addition it will document the development optimization scenarios that were performed for all reservoir levels to maximize recovery. It shows that even for relatively small reservoirs the use of reservoir modeling and simulation can be cost effective by allowing the optimization of production conditions, improved recovery and the prevention of unproductive well interventions.
The Key Challenges for Pliocene Reservoirs Exploration in West El Manzala and West El Qantara Concessions, East Nile Delta Onshore, Egypt
Authors: Salvadori Leonardo , Raslan Samir , Fathy Mohamed
Published: February 2010

Abstract

Exploration drilling in the Nile Delta has dramatically risen over the past 3 years, jumping from 5-10 wells/year up to 20-25 wells/year. Much of this recent drilling has been targeting the highly successful Pliocene play trend and the 2008 industry success ratio approached a phenomenal 90%. Thick sequences of Pliocene deep marine sediments have been successfully drilled and led to several offshore gas discoveries. No great exploration interest had been directed towards these good reservoirs in the onshore areas of the Nile Delta. Nevertheless, Dana Gas has been one of the most active and successful operators for this exploration target in its West El Manzala and West El Qantara Concessions.

The gas sands of the Pliocene reservoirs are characterized by low velocities and densities compared with the surrounding shales and, subsequently, the top and base of the reservoirs have a "bright?? seismic amplitude response. Additionally, the gas charged Pliocene reservoirs are often associated to acoustic impedance anomalies presence. The key challenge in the Pliocene reservoirs exploration is to understand the depositional environment with respect to the amplitude and acoustic impedance geometry from 3D seismic data through the cross-correlation between seismic facies character and the depositional pattern and environment.

The main features and variations recognized in the reservoirs drilled to date in West El Manzala and West El Qantara Concessions show a slow activity in the main basin evolution stage that seems to be not affected by high turbidity current flow or significant slope channeling. The early stage broad and straight channel system valley was cut and filled by younger channelized systems. Minor incisions of channel cuts are considered to be a key feature in defining channel fill development and sand distribution.
Innovative and Cost Effective Completion Technique for Saturation Surveillance Wellbore in Ratawi Reservoir of Wafra Field PNZ-Kuwait
Authors: Utomo B.. , Cullen R.. , Elbalasy S.. , El-Gendi O.. , Razzak S.. , Al-Hamdan M.. , Pasicznyk A.. , Fadda A.. , Glaser M.. , Erdmann L..
Published: February 2010

Horizontal sidetracking and waterflood are part of current Wafra Ratawi reservoir management strategies. These have proven successful to arrest production decline. A comprehensive surveillance program is considered to be the key to optimize waterflood performance. Saturation profile is one of critical parameters to understand waterflood sweep efficiency. The best way to acquire saturation data is by running saturation logs in vertical wells. Since horizontal sidetracking is one reservoir management strategy, the remaining vertical wells accessible for saturation logging are becoming limited and soon will not be available. This paper discusses an innovative and cost effective approach to this surveillance challenge. A combination of permanent fullbore oriented packer and retrievable whipstock, a selective re-entry system, was chosen to complete the wells. The existing vertical wellbore was converted to an observation wellbore before sidetracking. This technique has potential to save significant capital investment by using existing vertical wellbores to serve saturation surveillance purposes.

Since the intent is to run saturation logs periodically in the vertical observation wellbore and to produce through the horizontal lateral during normal operation, there are several operational challenges that must be resolved. These mainly include: debris falling during ESP well services, re-entry jobs in horizontal lateral by work string, and effect of squeeze cement operation on cased-hole logs readings. This paper also discusses how the proposed completion techniques overcome these issues.

Three wells have been successfully completed with this system. The first time-lapse cased-hole logs were also successfully run in one of these wells, including an attempt to re-enter the horizontal lateral by work string that went smoothly. This unique concept of saturation surveillance wellbore in horizontal producers can also be extended for new drill infill producers completed with cased pilot hole. The technique is considered to be an innovative and first time application across the globe.
New Engineered Approach to Replace Oil-Based Fluids with High Performance Water-Based Fluids in Mediterranean Sea
Authors: Attia Mohamad , Elsorafy Wael , D'Angelo Stefano
Published: February 2010

Oil-based fluids (invert emulsion fluids) have for many years been the fluid of choice for use in challenging hole sections. These fluid systems can bring many advantages, including optimal shale stability, low torque and drag, good resistance to contamination, and high drilling rates. One of the challenges of utilizing an invert emulsion fluid, however, has been the increasing level of environmental concern and legislation associated with its use. These challenges have driven the search for a high performance water-based fluid that will provide oil-based fluid performance and be environmentally acceptable in all offshore areas of the Egyptian Mediterranean Sea.

A novel, environmentally compliant high performance water-based fluid (HPWBF) system has been developed that has proven to be extremely inhibitive and highly lubricious.

Use of this new HPWBF system has helped operators to drill some of the most reactive shales in the Egyptian Mediterranean Sea while avoiding the high cost and safety risks associated with "skip and ship" operations. This performance is coupled with excellent cuttings integrity, increased temperature stability and good hole-cleaning properties. In the application of this system, the engineered approach matches fluid requirements with local clay characteristics, environmental regulations and operational objectives.

A HPWBF was chosen to drill Petrobel's well Karam-1 with a great success. The fluid was utilized to drill 334 meters of 12¼" hole section through the very challenging highly reactive formation of Kafr El-Sheikh stratum. The following conditions existed for this operation: Fluid must be water-based to meet environmental stipulationsThe shale section would be exposed for up to 10 days while loggingBottomhole temperature is 230°FApproximately 100 m 17½" rat hole existed below the 13 3/8" casing

This paper discusses the technical challenges and highlights the criteria for the proposed fluid system and the successes achieved in this well.
Reservoir Saturation Monitoring United with Production Flow Profile for Efficient Reservoir Management -Success Story of Workover Program on S.E. Gemsa Field by Combined Services "Production Logging and Pulsed Neutron Logging Tools"
Authors: Abugren Yosra Y. , Hassan Ahmed , Joshi Sameer
Published: February 2010

South East (S.E.) Gemsa is an oilfield located in Gulf of Suez (GOS) in Egypt. Many challenges have been faced in the reservoir and operation management of this field, such as: -Permeability contrast and water breakthrough in high permeability zones.-Non-uniform vertical water distribution.-Lack of water injection support across zones of low permeability.-Down hole scale build up.-Surface facility "bottlenecks".

One of the most critical problems was non-uniform water injection breakthrough into well SE-10B, which is a key oil producer in this field. This paper describes the water diagnosis and well intervention procedure carried out on this well over a period of 2 years (2007/2009) and the results achieved.

The main objectives of the conformance workover program were: -Reduce the water production.-Produce the non-contributing intervals.-Enhance the sweep efficiency by adding new intervals.

SE-10B is a deviated well (41 degrees) equipped with dual completion string to allow non-commingled production from strata with differential depletion and permeability contrast across the reservoir layers. This well was producing with very high water cut (WC) 95% from both strings. The major operational concern was to diagnose the water source; hence it was decided to run the combined Production logging and Pulsed Neutron logging tools to achieve the main objective of Water Shut-off (WSO).

The first logging run was in March 2007. The operator designed a workover program based on the interpretation results which showed the sources of main water contribution.

Workover-2007 results tended to increase oil rate by 275% (200 bopd to 750 bopd) and WC dropped to 30% in the long string. The short string did not have any water conformance intervention during this workover; it was producing at 98% WC and was shut down.

Another campaign was carried out in February 2009 for time lapse analysis and another conformance workover was implemented, which had impressive results. The short string has started producing 520 bopd with zero% WC versus mostly water before WSO. Long string has produced 1500 bopd and 25% WC versus 250 bopd and 65% WC before WSO.

The workover achieved a major reduction in WC levels of both strings, and had a significant positive impact on the daily oil rate that increased considerably to more than 300% of the value before the workover. All the objectives defined were achieved. The outcome of the workover program was completely successful and exceeded operator expectations.
Rejuvenation Issaran Field – Case Study
Authors: Samir M..
Published: February 2010

Issaran was discovered on 1981 and the cumulative production up to 1998 was 0.7 MMbbls from 9 wells and the total reserve were 5 MMbbls from 500 MMbbls as original oil in place which result in a recovery factor less than 1% and reflect the big challenge to produce this field.

The problem was that each reservoir has its own characteristic, which requires special approach to overcome its problems and optimize its production and reserves. As Zeit Formation contain massive sand, Upper and Lower dolomite due to its shallow depth the oil could not be produced as cold production, Gahrandal formation is consisted of three limestone bodies with permeability below 20 md and the last one is Nukhul zone which give some cold oil production due to its naturally heavy fracture. Theses difference characterization lead to apply different ways of reservoir management for each zone.

The challenge of Scimitar is to produce these zones and reach to a production plateau in spite of the aging of the fields and its associated problems (low pressure, water cut increase, wells potential, sand production and corrosion, …. etc). Scimitar dedicated special multi disciplinary teams to propose and implement several strategies to achieve its goal and succeeded to have stable plateau around 6000 BOPD during year 2008.

This paper will highlight the results of each zone and the achievement as the total wells drilled on the field up to now is 287 well and the total OOIP increases to 700 MMbbsl, the cumulative oil production on March 2009 is more than 10 MMbbls which gives more confidence about the successful of the new strategies for each zone. The steam project applied on the Lower and Upper Dolomite is consider the first successful cyclic steam project on the Middle East. The results of the producing wells in conjunction with the numerical 3D simulation study lead to prove that the recovery factor can be reach to 45% which gives total reserve around 300 MMbbls.
Role of Steam Injection Pressure to Achieve Successful Cyclic Steam Project Issaran Field - Egypt
Authors: Samir M..
Published: February 2010

Issaran fied Upper Dolomite Zone were subjected to a steam project by year 2006. The steam injection pressure is very important factor during the steam cyclic project as at any single injector difference in the performance of nearby wells may be attributed to (1) local differences in reservoir characteristics and initial fluid contents, (2) anisotropy in properties (perhaps a preferred fracture orientation), (3) effects of dip, (4) differences in well completion, operation, or impairment, and (5) differences in the location of fluid fronts in the reservoir.

Normally the injection pressure measure during thermal operations to provide (1) information on the injectivity and productivity of wells and flow resistance in the reservoir, (2) confidence that equipment and wells are being operated at design pressure levels and within safe pressure limits, (3) information on the enthalpy of fluids, and (4) information about properties and conditions existing in the reservoir through the use of diagnostic well test and continuous pressure observations.

The injection pressure play very important role on the oil production after the injection period. Here will discuss the pressure performance while steaming and its effect on the average oil production on the production period after. On Issaran Upper Dolomite fracture zone, 16 wells were subjected to two steam cycles and based on the injection performance these 16 wells were subdivide to three groups, the first group for the wells which showed a decline on the oil rate after the second cycle, second group for the wells showed sustain on the oil production after the second cycle and the third group showed an increase on the oil production after the second cycle.

This paper will highlight these results, and the methodology taken for analyzing the data, and the ways of investigation taken to reach a certain conclusion by the injection pressure should not exceed the fracture pressure otherwise during the second cycle the average oil production will be decrease.
Transient Well Performance Modeling for Reservoir Pressure Determination
Authors: Yee Hon Vai , Zainal Suzalina , Saaid Ismail
Published: February 2010

Continuous reservoir pressure data acquisition through intrusive well intervention has always been a challenge to the industry due to a combination of economic, operational and logistical constraints. This paper presents an alternative methodology wherein the reservoir pressure can be computed from the well's steady-state flow properties and wellhead shut-in data using an advanced transient well algorithm.

The key research element is the incorporation of mass transfer rate model into dynamic wellbore modeling for shut-in well. A mathematical workflow which incorporates the time dimension as inherited in the mass transfer theory is devised. This is a major advance on prior state-of-the-art models that assume instantaneous mass transfer upon equilibrium. This enhanced dynamic well model is able to simulate the fluid redistribution during well shut-in, by determining an accurate volume of each fluid phase at any cell in the well over time. Hence, the bottom-hole pressure over time can be calculated by adding the static head to the wellhead pressure. The bottom-hole near wellbore reservoir pressure is obtained when the well has reached equilibrium. The model also rigorously accounts for various transient behaviors of the reservoir fluids during shut-in including the reservoir fluid influx.

A number of engineering concepts are evaluated and all the elements that become the foundation of this novel methodology are presented. A sample well is used to demonstrate the robustness of the model in simulating the hydrocarbon fluid redistribution during well shut-in. A better description of wellbore dynamic behavior is obtained, ensuring an improved accuracy in transient well performance modeling.

This enhanced dynamic well model provides a vital tool for reservoir pressure determination, replacing subsurface data acquisition with surface data acquisition without well intervention. The model enables operating costs reduction associated with subsurface data acquisition, in addition to improve key data availability which will optimize production plans and recovery improvement opportunities.
Uncertainty Evaluation in Emerging Gas Projects in North Africa Using Geological Modeling, Reservoir Simulation and Experimental Design
Authors: Vicente M.. , Moreno F. J. , Limeres A.. , Ozamiz E. Izaguirre , Rieu R..
Published: February 2010

In this study the main uncertainties affecting the reserves estimation in the low permeability Lower Devonian gas reservoirs of an exploration block in Algeria are evaluated. This large gas project faces significant uncertainties as a result of the ambiguities in reservoir quality, architecture and well performance. Therefore, a comprehensive risk analysis is essential to manage the production forecast and the surface facilities sizing evaluation.

Although there have been important advances in terms of reservoir modeling and simulation, the reserves risk analysis remains as a challenging task in the early exploration phase of large projects. Traditional studies commonly use only one geological model for the simulation (P50 or mean case), and the uncertainties are evaluated using a one-parameter-at-a-time approach assuming no dependency among them. Finally, this unique case is adopted to take decisions based on the economic output results analysis and the project commitments.

An alternative to the traditional evaluation is the use of Experimental Design (ED). An analytical equation ("response surface model") is created and this surrogate model is used to study the interaction of all variables and their impact on the simulations. The experimental design coupled with multivariable regression and Monte Carlo simulation could be used for final parameters evaluation. Relatively few real case examples of this technique have been documented, and commonly these applications do not integrate multiple deterministic geological models.

In this paper we present an example of how static and dynamic uncertainties were integrated using a scenario-based approach and ED, building the models and concentrating the study on the variables that control the recovery: reservoir quality, distribution and connectivity, porosity, permeability and fluid contacts. This work helped to quantify the uncertainty for reserves, number of wells and gas rate deliverability estimation, adding significant value to the current field development plan assessment.
Qualitative and Quantitative Interpretation: The State of the Art in Temperature Logging
Authors: Valiullin R. A. , Ramazanov A. Sh. , Pimenov V. P. , Sharafutdinov R. F. , Sadretdinov A. A.
Published: February 2010

In the paper it is described the achievements in the modern well thermometry and analyzed the problem of quantitative interpretation.

It is known the first logging in oil wells was temperature one. In 1906 the professor D. Golubyatnikov on Apsheron (Azerbaijan) at first time measured the temperature distribution along the wellbore using the maximal thermometer. Today the high sensitive electronic thermometers with resolution of 0.01K are used: it is registered and analyzed the temperature changes of hundreds and tens parts of degree, caused by Joule -Thomson effect and adiabatic effect.

At present time the most volume of production log is accounted to thermometry. In the paper it is given the examples of field cases from Russia by means of well thermometry during the development using the gas (air) compressor. The results of practical testing of new methods of well thermometry as "active thermometry", which is based on local inductive heating of casing on the different depths and observing the behavior of the transient temperature, are discussed.

It's known that despite many attempts to develop quantitative interpretation methods, the interpretation of temperature measurements has remained mostly qualitative. The paper describes the mathematical models, used at interpretation of temperature logs. The most recent results are connected with quantitative interpretation of quasi-steady temperature distribution along the well and pressure and temperature transients with the purpose of determination of flow rates and individual parameters (for example, radius and permeability of damaged zone) of formation in multilayer wells. The application of the developed models to interpretation of temperature measurements in the different wells demonstrated on real field data sets.
3D Exploration for Remaining Oil Using Historical Production Data
Authors: Ling Yun , Huang Xuri , Guo Xiangyu , Sun Desheng , Gao Jun , Lin Jixiang
Published: February 2010

3D and 4D (or time-lapse) seismics are techniques commonly used for exploration and reservoir exploitation. Increasingly, time-lapse seismic is becoming a more popular tool for reservoir development and management. However, its application is constrained by reservoir conditions, production mechanisms and seismic data repeatability. The technique of 3D exploration for remaining oil with historical production data (called a 3.5D seismic approach to differentiate it from time-lapse seismic) uses high quality 3D seismic data, acquired after a certain period of reservoir production, and integrates them with historical production data to provide information for reservoir dynamics, such as the identification of additional resources and the delineation of remaining oil. In integrating the 3D seismic with historical production data, the 3D seismic data are time-stamped and then related to the reservoir dynamics. This enables 3D seismic data to represent reservoir dynamics in time. In this paper we present a case study in an onshore mature oil field in western China, where no baseline 3D seismic survey is available, with production data spanning a period of 16 years from 1990 to 2006, and with a 3D seismic survey acquired in 2006. The results show that the 3.5D seismic approach can identify reservoir potential and remaining oil.
Enhanced Formation Evaluation and High-Resolution Facies Determination Using Spectroscopy Logs in the Nile Delta, Egypt
Authors: Van Steene Marie , Farghaly Adel , El Fotoh Ahmed Abu , Herron Susan
Published: February 2010

Computing clay volume using elemental neutron capture spectroscopy logs in combination with a multimineral solver for the complex, shaly sand reservoirs of the Nile Delta reservoir improved accuracy over using the mineral fractions output from the spectroscopy model alone. It was also found that the aluminium log from direct aluminium yield measurement leads to a better clay volume estimation, as opposed to using the aluminium log from the aluminium emulator algorithm.

Combining the spectroscopy data with borehole image data generated a high-resolution lithofacies column that provides an accurate stratigraphic interpretation. Applying cutoffs to generate a high-resolution sand count enabled us to sort the reservoir units from the poorest to the best quality sands and improved our understanding of the distribution of the best reservoir quality in the well. This approach provides a unique solution to characterize thinly bedded reservoirs in wells drilled with oil-based mud.
Challenges Facing Marine CNG Transportation
Authors: Nassar Yehya Mohamed
Published: February 2010

Natural Gas is recently becoming the more popular energy source worldwide and its use is expected to increase dramatically over the next two decades. Natural Gas has been gaining wider significant as a result of sustained high oil prices, a need for energy diversification and security, the growing global awareness of environmental issues, and due to the development of new gas-related technologies.

Traditionally natural gas has been delivered to markets using two main commercially-proven methods; Pipelines and liquefied Natural Gas (LNG). Each of these alternatives is highly capital-intensive and requires considerable working terms regarding the quantities and distances to market. In other words these two methods are only economic over a specified range of quantities and distances and not the whole range, which opens the door to a number of alternative technologies that have the potential to make the development for smaller quantities to be transported to specific distances.

The most advanced among these alternative technologies include Onshore Gas-to-Liquid (GTL), Floating LNG and GTL, Natural gas hydrates (NGH), Adsorbed Natural Gas (ANG) and Compressed Natural Gas (CNG). None of these however, has yet been developed and proven on a commercial scale, although they have proven themselves viable on technical parameters.

This paper will be concerned mainly with Marine CNG alternatives, which are currently in their final stages of commercialization, indicating the various available Marine CNG technologies used worldwide and focusing on the operating differences between LNG and CNG transportation and finally technically and economically evaluating both the obstacles and advantages facing the commercialization of Marine CNG transportation.
A Study of Coupling Surface Network to Reservoir Simulation Model in a Large Middle East Field
Authors: Al-Mutairi Saad , Hayder Ehtesham , Munoz Alberto , Al-Shammari Ahmed , Al-Jama Nayif
Published: February 2010

This study investigated the feasibility of coupling a subsurface numerical reservoir simulator (POWERS) with a surface network modeling simulator, to assist in making better field management decisions according to business need. Coupled simulation models have two advantages over uncoupled models. First, interdependence of the reservoir and surface facilities are properly modeled in coupled simulation models to accommodate rapid variations in production strategies. Coupled simulation models are likely to give more accurate production forecasts compared with modeling the reservoir or the surface separately. Second, given that most surface network modeling tools have a built-in optimizer, it is possible to allocate rates among wells based on a user's objective optimizing function, — e.g., reducing or maintaining a water-cut level for a given production target — taking into consideration any system production constraints applied on a well, a group of wells or trunkline levels. To improve the quality of simulation results, a new algorithm is implemented in POWERS to calculate the inflow performance relationship (IPR), based on drainage pressure, i.e., a reservoir pressure calculated as the average of several neighboring cells in the simulation model as opposed to the single cell pressure. The current study shows that it is feasible to run coupled POWERS-surface network models and gain the benefit from the optimization algorithm of the surface network modeling tool.