bluuebunny/crossref_metadata_2025 huggingface dataset:
Aligning E&P Organizations to Manage Large Capital Projects
Authors: Luan Pete , Wray John
Published: December 2007

Planning and executing large, high risk, capital projects in frontier areas means that E&P organizations have had to retool their project delivery systems. While many energy firms have started the development of more robust project management processes to support these high capital expenditure (CAPEX) projects, implementation of this new way of doing business is meeting limited success.

Business leaders feel that they must effect change because of lack of predictability in delivering major E&P projects as evidenced by the above headline. This lack of predictability includes CAPEX overruns, late project completions, overly optimistic recoverable reserve estimates, etc.

By some estimates, 50% - 80% of enterprise level initiatives are deemed failures by organizations. How much stockholder’s equity has been liquidated attempting to implement a new way of doing business yet meeting only limited success, if any at all?
Robust Well-Cost Estimation Using a Support Vector Machine Model
Authors: Bhuddharaju Pradeep , Laskar Sandipan , Samuel G. Robello
Published: December 2007

The preparation of cost estimates for a well is the final and most critical step in well planning. Traditionally, well costs are estimated by using a deterministic calculation procedure with time and cost inputs, or by using probabilistic methods. Because in many cases the estimate determines whether or not the well will be drilled, the credibility of the estimated cost is crucial.

This paper describes the development of a support vector machine (SVM) -based application. In addition to estimating the cost, this application also indicates the percentage of accuracy in the prediction, thereby proving the credibility of the predicted cost estimate. The proposed methodology enables drilling industry personnel to estimate the risk of the project during well planning and during drilling. The analysis from such a model is based on the constraints of different drilling variables. Extensive simulations have been carried out and are reviewed in this paper. The paper also includes two case studies of well cost estimation where the SVM methodology successfully the predicted risk involved in the completion of the wells.
The Application of Expandable Tubulars in Casing while Drilling
Authors: Gupta Yash , Banerjee Sudeepto N.
Published: December 2007

The basic idea of a mono-bore well has been a dream in the oil and gas industry since its very origin. With the development of new technologies, this dream is becoming a reality. The two most preferred methods for drilling a single diameter well are the casing while drilling system and the expandable tubulars. Both these methods are useful in their respective fields of applications. But both these technologies have not been used simultaneously, not even in a single well as separate methods for drilling.

This paper discusses the possibility of combining these two technologies, namely the casing while drilling method and expandable tubulars, for tapping the advantages of both these technologies. The main advantages that are evident by this combination is the savings that are achieved, both in terms of monetary and time. Also further reduction of tools involved leads to less chances of failure, again leading to savings in terms of manufacturing and logistics. This paper also focuses on the different mechanical properties of the casing type to be used for this specific purpose and discusses general complications that might arise in practical field applications of the same.
Maximizing Well Productivity through Water and Sand Management—A Combined Treatment
Authors: Nguyen Philip D. , Ingram Stephen R. , Gutierrez Mauricio
Published: December 2007

Production of large volumes of water, coupled with production of formation sand and fines from oil and gas wells, often curtails the potential production of hydrocarbon. It is therefore highly desirable to decrease the volume of water and mitigate the solids produced from producing wells. Water and sand control generally have been addressed as separate problems with different treatment solutions. This paper discusses the development, and presents the field testing results, of a 2-step process that combines both water- and sand-control treatments into a single treatment.

Laboratory experiments were performed to examine the impact of these combined treatments. The relative permeability modifier (RPM) treatment results in water permeability reduction with little or no reduction in permeability to oil. Treatment with a consolidating agent transforms the unconsolidated formation sand and/or loosely packed proppant into a cohesive, consolidated, yet highly permeable, pack. The combined process has been field tested successfully. Results from field tests have shown that this process helped reduce on average 50% of water production, effectively eliminated the production of formation sand, and allowed the wells to withstand high production flow rates.
Mercury Removal System for Upstream Application: Experience in Treating Mercury From Raw Condensate
Authors: Sainal Muhamad Rashid , Shafawi Azman , Mohamed Ir. Abdul Jabar
Published: December 2007

This paper presents an approach undertaken by PETRONAS Carigali Sdn Bhd, an E&P subsidiary of PETRONAS in selecting, optimizing and installing a mercury removal system in one of its operations in Malaysia. It focuses on the treatment of the raw condensate stream that was noted as having much higher mercury content as compared to the gas stream. Since the experience in mercury removal in raw condensate is limited, this paper also presents the work done to mitigate the risks and improve the removal performance. The paper shares the initial performance of such system and the issues faced to sustain its long term effectiveness.

Through operation surveillance, mercury was observed to be present in the hydrocarbon delivered by PETRONAS Carigali to its downstream customers. A Mercury Removal Project was initiated in March 2005 to treat and remove the mercury from the hydrocarbon. The Project was conducted on a fast track basis. Adsorbent technology was selected following a thorough evaluation that includes carrying out performance tests in the laboratory. The project is among the first in the world to remove mercury from raw condensates. (The gas was not treated after the data established that the mercury content in the gas meets specifications).

The project was completed in stages with the first system installed in March 2006, and the second in July 2006. The results show that the units managed to remove mercury from the condensate with more than 95% efficiency. The project demonstrated that the treatment of mercury could be done upstream prior to exporting the hydrocarbon liquids. It is an approach that should not be ruled out in the gas processing value chain whether for reasons of risks mitigation or value improvement or both.

Mercury is a natural occurring element and could be present in varying concentrations and of various species in oil and gas fields. Mercury is not only hazardous to human health and the environment but could also attack equipment components that have mercury reactive materials, leading to a potential catastrophic failure to the plant.
Neural Networks Can Enhance Fuzzy Corrosion Modeling
Authors: Hajizadeh Yasin
Published: December 2007

Corrosion in the petroleum industry is one the major concerns of the managers and engineers. Both upstream and downstream parts face this problem and the companies spend billions of dollars in this case. To remain competitive with the world market and win the game, this cost must be kept to a minimum and here the large demands for a reliable corrosion prediction model do exist which we can use in our decision making. On the other hand in many engineering problems the available information is vague and sometimes measured data or export knowledge is too imprecise to justify the use numbers. Fuzzy logic is a good solution here and helps us to compute with words. But the problem is that you can not train the fuzzy systems so neural networks may be useful here to add learning capability to fuzzy systems.

Using fuzzy logic as a powerful tool, 3-D corrosion models have been generated in the previous work. In this paper the problem of corrosion modeling will be discussed form the hybrid neurofuzzy approach. Teaching the fuzzy system with neural networks, and using pressure, temperature, oil and gas production rate, CO2 and H2S mole percent of the flow as the model inputs and the corrosion rate as the output, 3-D surfaces for the corrosion have been obtained and the prediction results of the model which is based on the pattern recognition between input and output parameters is tested. These graphs can be used as a reliable tool in corrosion prediction by managers and engineers.
Relative Permeability and Wettability of Rocks Obtained From Their Capillary Pressure and Electrical Resistivity Measurements
Authors: Attia A. M.
Published: December 2007

Relative permeability and Capillary pressure characteristics of reservoir rocks are usually determined using core analysis. In the absence of representative core sample, resistivity log-derived water saturation in the transition zone may be used to depict capillary pressure curve and, in turn to determine relative permeability characteristics from petrophysical correlations. Most of reported research works have investigated the relative permeability from a steady state and unsteady-state techniques. The technique of measuring relative permeability using resistivity measurements almost absent from the reported works. Hence, the main objective of this work is to determine the relative permeability from the resistivity measurements and compare it with those obtained from capillary pressure data using the same cores. Also, it is intended to find out which models could be used for calculating the relative permeability from capillary pressure realizing a best fit matches with the relative permeability obtained from resistivity measurements. In addition, to determine the types of wettability from resistivity measurements. Results and analysis indicate that the capillary pressure and resistivity measurements result in significant different irreducible water saturation values. This, in turn, results in substantially different relative permeability characteristic curve. Also by analogy, a semi analytical method was to be developed to infer relative permeability from resistivity index and free water saturation. In most cases, the Brook-Corey and Corey models, may be the best fit match to the relative permeabilities of wetting and nonwetting phases respectively obtained from resistivity measurements. Therefore, wettability was determined using the values of water saturation exponents, water saturation at crossover point. The results indicate that, the wettability of Berea cores was neutral-mixed wet. However the wettability of the synthetic cores compacted at 3000 psi, was strongly water wet.
The Effect of Tool Joints on ECD While Drilling
Authors: Simoes Sarita , Yu Mengjiao , Miska Stefan , Takach Nicholas E.
Published: December 2007

As the oil and gas industry moves toward drilling ultra-deep and deepwater wells with small margins between pore pressure and fracture gradient, management of ECD becomes a key factor in the successful drilling of these wells. ECD is governed by the hydrostatic head of the mud column and frictional pressure loss in the annulus, and therefore is influenced by many factors such as well and drillstring geometry, drilling fluid rheology and flow rates. Many theoretical and experimental studies have dealt with the flow of fluids through pipes and annuli for friction pressure loss calculations. However, the effect of tool joints in estimating pressure losses in annuli in many cases is underestimated or ignored. Although a single tool joint is short and does not increase the frictional loss drastically, the overall contribution to the increase in ECD by all the tool joints in the wellbore can be significant. Therefore, there is a strong need to investigate the effects of tool joints on ECD control.

This paper presents results for a theoretical study conducted through Computational Fluid Dynamics techniques to evaluate the influence of the tool joints on ECD for different wellbore geometries, drilling fluids and flow rates. It is found that the effect of the tool joint on the annular friction pressure loss is significant and should be taken into account in the optimal hydraulic program considerations.
Shifting Paradigms—Underbalanced Drilling Technology Proves Highly Successful for Reservoir Evaluation and Drilling Performance Improvement in Kuwait
Authors: Vieira P. , Larroque F. , Al-Saleh A. M. , Ismael H. , Qutob H. H. , Chopty J. R.
Published: December 2007

The Shuaiba formation in the Raudhatain field is a highly fractured limestone reservoir. Conventional drilling technology in this formation usually results in a complete loss of drilling fluids to the formation. These losses cause severe formation damage which results in masking the evaluation of the potential for hydrocarbon production.

Underbalanced Drilling Technology was proposed as an alternative drilling method. The main objective of the UBD drilling application was to evaluate the potential of hydrocarbon in the Shuaiba formation while simultaneously eliminating fluid loss to the formation and improving drilling performance.

This well was the first well drilled underbalanced by KOC, a training program was prepared in order to familiarize the rig personal involved with the operation of the UBD equipment and procedures. The openhole section was drilled out of a 10 ¾" casing with an 8 ½" bit. A conventional mud pulse MWD/PWD/LWD tool with real-time annular pressure, temperature and gamma ray sensors were incorporated in the BHA. The use of MWD/PWD/LWD provided a means of monitoring the downhole underbalanced conditions and formation properties while drilling. The Shuaiba formation was successfully drilled underbalanced without any fluid loss during the drilling phase. The openhole section was drilled to a total depth (TD) of 8942 ft MD, with an openhole length of 242 ft.

Integrated efforts of KOC and service companies of various disciplines during planning and operation stages of the well led to the success of the project. No QHSE incidents were reported.

This paper highlights the key factors in the underbalanced drilling design phase, the operational challenges faced, and the results of the first well drilled in Kuwait using underbalanced drilling technology.
An Improved Model for the Liquid-Loading Process in Gas Wells
Authors: van Gool Frank , Currie Peter K.
Published: December 2007

This paper introduces an improved model for describing the liquid loading process in gas wells. The model is an extension of the model proposed by Dousi et al (2005).

The Dousi model handles the downhole inflow and outflow between the well and the reservoir in a simple manner. The new model improves this aspect, and makes more realistic and detailed assumptions with respect to the production and injection interval. Analysis using this new model improves understanding of the processes occurring downhole. Also it can be used to predict future behaviour of the well in a more realistic fashion. As in the Dousi model, two typical flowrates could be found, one at full production with all the fluids produced to the surface and one meta-stable rate where produced fluids are being re-injected into the reservoir. Field observations confirm the existence of two possible flowrates in many wells. The difference between the new model and the Dousi model is that changes in flow rates occur more slowly when liquid loading starts, reflecting the more realistic inflow performance assumptions.

With this model, liquid loading processes in the well can be better understood and predicted. This is important for optimisation of well performance and the economic assessment of the well and field.
Methane From Gas Hydrates Using Methanogens
Authors: Abraham Leo T. , Varma Esha N.
Published: December 2007

The growing need of energy and the depletion of the conventional resources i.e. the fossil fuels have led us to think seriously about the non conventional resources like solar, tidal, wind, waste energy, etc. Apart from these resources the science and technology is rather focusing more on gas hydrates. Natural Gas which is an important source of energy is being consumed about 85 trillion cubic feet per year. The current natural gas reserves show that they will last only for 60 years at this rate of consumption. But luckily the reserves of gas hydrates (natural gas) are enough so as to provide 100 percent of the present energy and will serve upto 2000 years, but we aren't able to extract them economically.

The idea of ‘EXTRACTION OF METHANE FROM GAS HYDRATES USING ANAEROBIC ARCHAE-BACTERIA’ may not only help in extracting methane from gas hydrates but also may convert water and carbon di oxide present in gas hydrates into methane. In this idea, I propose the use of anaerobic archaebacteria namely methanogenic archaebacteria, to convert carbon di oxide and water to methane. The above process is exothermic in nature that liberates heat, which can increase the temperature of water above its boiling point and cause gas hydrates to liberate methane. The characteristics of the anaerobic archaebacteria satisfy the conditions of existence of gas hydrates.

Thus, these bacteria may help in extracting methane from gas hydrates effectively and efficiently.
Productivity Tests: The Method for the Pre- and Post-Evaluation of Workover/Stimulation Jobs
Authors: Medina R. A.
Published: December 2007

At first, this paper presents the bases for a new approach of well testing focused on to determine well-reservoir properties from Flow-After-Flow tests. This approach opens the unprecedented real opportunity to use tubinghead pressure data as a powerful tool of analysis.

After that, the paper presents the evaluation of a field test to show the operational simplicity of the approach in evaluating a producing well either before or after a workover/stimulation job.

Lastly, it is proposed to make a further use of this new well testing approach in the industry to develop statistically: (a) The characteristic profile of "Initial-vs.-Final Skin Factor", for each kind of workover/stimulation job at each specific exploitation area; and (b) The characteristic profile of "Skin Factor through the Time", for each specific exploitation area. These profiles will let respectively, a more precise screening of the future stimulation candidates, and the forecast of the future stimulation jobs required in a zone to keep optimized its productivity.
Using Risk-Based Analysis To Identify Inspection Priorities
Authors: Belieu Stan , Kell Scott , Jehn Paul , Lowther David , Gillespie Deborah
Published: December 2007

Onsite inspection is the most expensive component of any regulatory oversight program, and agencies have been looking for ways to manage these programs cost-effectively while maintaining the same level of environmental protection. Developing the data analysis tools to monitor water quality and to assess available supplies has become critical to resource management. In response, the Ground Water Protection Council (GWPC) is expanding its Risk Based Data Management System (RBDMS) into source water quality protection, laboratory information management, produced water management, and water quantity assessment. RBDMS for Water tracks water and waste stream parameters and makes site-specific monitoring data available in a geographical information system (GIS) format. This paper discusses how RBDMS for Water is being customized by two regulatory agencies as a management and planning aid in refocusing their field inspection programs. These agencies are tasked with continuing to meet environmental protection goals in the face of stagnating funding and escalating real costs for these programs. The agencies: the Nebraska Oil and Gas Conservation Commission (NOGCC) and the Ohio Department of Natural Resources (ODNR).
Comparing Rigless Water-Cut Reduction Methods
Authors: Xue Yan , Yang Anping
Published: December 2007

High water cut is often the main factor affecting economical production of an oil well. There are mainly three technologies for reducing water cut: mechanical shutoff in production well, chemical treatment of production well, and injection well profile control. This investigation focuses on low cost rigless methods, comparing their potential effectiveness and economics based on existing applications and computer simulation.

There are mainly two types of rigless methods for water-cut reduction. One is mechanical method when each zone is isolated with packer and choke-sleeve during completion so that choke can be changed for each zone, including shutting the zone off completely, with a slick-line unit. Another is chemical method which depends on injecting agents into production well where the agents selectively reduce high permeability zone permeability or reduce water relative permeability without much damage to oil permeability. Chemical methods may also be used in fractured carbonate reservoir, though it is more difficult to be successful.

Our investigation shows that under suitable conditions, rigless water-cut reduction methods can be cost effective. Computer simulation can be used as a tool to support the selection of a suitable method and help predict the effectiveness of the plan.

Since there are many marginal wells and many of them are limited by high water cut, increased application of cost effective water-cut reduction technologies will improve the economics of these wells and prolong their life, increasing oil production.
Evaluation of the Potential for Gas and CO2 Leakage Along Wellbores
Authors: Watson Theresa L. , Watson T. L. , Bachu Stefan
Published: December 2007

Implementation of carbon dioxide storage in geological media requires a proper assessment of the risk of CO2 leakage from storage sites. Leakage pathways may exist through and along wellbores which may penetrate or be near to the storage site. One method of assessing the potential for CO2 leakage through wells is by mining databases that usually reside with regulatory agencies These agencies collect data concerning wellbore construction, oil and gas production, and other regulated issues for existing wells. The Alberta Energy and Utilities Board (EUB), the regulatory agency in Alberta, Canada, collects and stores information about more than 315,000 oil, gas and injection wells in the province of Alberta, Canada. The EUB also records well leakage at the surface as surface casing vent flow (SCVF) through wellbore annuli and gas migration (GM) outside casing, as reported by industry.

The evaluation of a leakage pathway through wellbore casing or annuli and what causes these wellbore leaks is a first step in determining what factors may contribute to wellbore leakage from CO2 storage sites. By utilizing available data, major factors which contribute to wellbore leakage were identified.

Data analysis shows that there is a correlation between these SCVF/GM and economic activity, technology changes, geographic location and regulatory changes regarding well completion and abandonment. Further analysis indicates a relationship between low annular cement top, external corrosion, casing failure and wellbore leakage (SCVF/GM). Other factors that could affect the presence of wellbore leakage, such as wellbore deviation, surface casing depth and wellbore density, were also investigated.

This paper presents the findings of the data analysis and a method to evaluate the potential for leakage along wells in an area where CO2 storage is intended. This information is useful not only for future operations of CO2 storage in geological media, but also for current operations relating to the exploration and production of hydrocarbons.
Technology Integration in the Caspian
Authors: Pannett Ian , Hodgson David
Published: December 2007

BP's Azerbaijan Strategic Performance Unit (AzSPU) has a very active and rich technology programme. It has been developed to meet the key challenges of operating within the Caspian region and to maximise business value. The key challenges facing the AzSPU that need to be addressed via the application of technology are: complex depletion plans, unconsolidated reservoirs, a difficult overburden to drill and an integrated development, gathering and export system. The key technology drivers are: reservoir management, new well delivery, drilling and completions performance, and facilities' operating efficiency.

To meet these challenges AzSPU has engaged in a number of key strategic technologies: advanced seismic, intelligent completions, zonal flow monitoring and control, and the FIELD OF THE FUTURE. These technologies collectively address the business challenges and will underpin superior business delivery.

Taken individually each of these technology areas has the potential to significantly impact the bottom line, but maximum benefit will only be realized when they are integrated along the value chain. The FIELD OF THE FUTURE programme in Azerbaijan aims to systematically integrate these technologies by optimising production and operating efficiency across this value chain, from the well's sand face 6km below the surface of the Caspian to the tanker 1760 km away in Ceyhan, Turkey.

AzSPU's the FIELD OF THE FUTURE programme has a detailed five-year plan and a longer term strategy. The value proposition for the first phase of this programme is to deliver 14mbpd by 2009. This paper outlines the FIELD OF THE FUTURE programme and highlights how it aims to integrate the whole value chain and maximise business value. This will include discussion on the key challenges and strategies involved, including technology development data analysis and interpretation, organisational capability and the integration of people, process and technology.
Underbalanced and Coiled-Tubing Drilling Technologies Successfully Applied in a Through-Tubing Horizontal Short-Radius Well in Hassi Messaoud Field, Algeria
Authors: Amor Bachir Ben , Ferhat Ali , Messas Rafik , Arnone Maurizio , Fudge Grayson , Stulberg Michael , Schoch Fritz , Qutob Hani , Chopty James
Published: December 2007

The Hassi Messaoud field (Figure 1), discovered in 1956, is the largest oil field in Algeria, covering about 2000 Km2 and currently including over 1000 Wells. The field is divided aerially into 25 zones that are separated from each other by low permeability barriers, usually faults. The Cambrian Reservoir is subdivided into four lithological zones designated from base to top as R3, R2, Ra and Ri. The Ra sub reservoir shows the best petrophysical properties with a maximum thickness of 150 m in the western part of the field. The Ra is farther subdivided into five sub zones: D1, ID, D2, D3, and D4 based on reservoir properties and depositional conditions.

Well F was the 6th re-entry well in the Sonatrach Coiled Tubing – Underbalanced Drilling campaign. A total of 363 m from KOP (303 m from landing point) were successfully drilled in a continuous underbalanced condition inside D1 and ID formations. As a result, the well productivity while drilling and while production test, the reservoir characterization and rate of penetration was significantly improved, compared with offset wells, due to the positive impacts of UBD operations.

The combination of Underbalanced and Coiled Tubing Drilling technologies has been proven to be a viable solution to successfully drill horizontal re-entry wells in mature fields where the reservoir pressure is adequate to induce underbalanced conditions using single phase or multiphase drilling fluid.

The experience in this field has validated the benefits of the combination of these technologies and has been attributed to the excellent balance between drilling cost and improved productivity. For example, the drilling cost in the short radius re-entry wells drilled with coiled tubing are highly reduced due to the elimination of pipe connection procedures, the increase in rate of penetration, the prevention of conventional drilling problems such as fluid circulation loses and related differential sticking events, the increase in the bit life and reduction in time and drilled distance to reach the profitable production level.

This paper describes the technical basis for the design and implementation of the Coiled Tubing Underbalanced Drilling project in Hassi Messaoud Field and highlights the operational key factors and challenges faced during this particular and successful application in Algeria.
Coil Tubing Deployed ESP in 5½ Inch Casing: Challenges in Designing Down
Authors: Mack John , Donnell Jimmy
Published: December 2007

In the short history of coil tubing deployed electrical submersible pumping (ESP) systems, 7 inch production casing has been the norm. However, recent applications with low flow volumes and high wax content require a smaller diameter production casing to maintain flow velocities capable of flushing the wax. The challenges of re-designing a complex coil tubing deployed inverted ESP were significant.
Inferring Interwell Connectivity from Well Bottomhole Pressure Fluctuations in Waterfloods
Authors: Dinh Anh , Tiab Djebbar
Published: December 2007

This paper presents a new procedure to determine inter-well connectivity in a reservoir based on fluctuations of bottomhole pressure of both injectors and producers in a waterflood. The method utilizes a constrained multivariate linear regression analysis to obtain information about permeability trends, channels and barriers.

Previous authors applied the same analysis to injection and production rates to infer connectivity between wells. However, in order to obtain good results, they applied various diffusivity filters to the flow rate data to account for the time lags and the attenuation. This was a tedious process that requires subjective judgment. Shut-in periods in the data, which were usually unavoidable when a large number of data points were used, created significant errors in the results and were often eliminated from the analysis.

This new method yielded better results compared to the results obtained when production data were used. Its advantages include: (1) No diffusivity filters needed for the analysis; (2) Minimal numbers of data points required to obtain good results; and (3) Flexible plan to collect data as all constraints can be controlled at the surface. The new procedure was tested using a numerical reservoir simulator. Thus, different cases were run on two fields, one with five injectors and four producers and the other with 25 injectors and 16 producers.

For a large waterflood system, multiple wells are present and most of them are active at the same time. In this case, pulse test or interference test between two wells are difficult to conduct since the signal can be distorted by other active wells in the reservoir. In the proposed method, interwell connectivity can be obtained quantitatively from multi-well pressure fluctuations without running interference tests.
Online Integrated Asset Models With Map-Based Visualization
Authors: Weber Michael J. , Vergari Alison Bondurant , Shippen Mack
Published: December 2007

BP North America Gas has completed the first stage of a ground-breaking R&D field trial in Arkoma, involving use of online integrated asset models and map-based visualization tools. This application called MAPS (Maximizing Asset Performance System) enables operators and engineers to geographically navigate and explore real-time operating data and model results across a large field, gaining new insights and interrelationships needed to optimize field and production performance.

In Arkoma and other assets, optimizing wells and facilities to achieve maximum performance requires sifting through volumes of data for hundreds of producing gas wells. MAPS is a new innovative means to geographically view and playback real-time data visually, enabling operators and engineers to navigate, explore, and discover information about the field and production. Through use of MAPS, online integrated asset models and real-time map-based visualization are now available to operations and engineering personnel from virtually any location, enabling better and faster identification of operating issues and opportunities for further action.

Integrity management issues are being addressed through use of MAPS and online models which are capable of providing insight and visibility into thousand miles of pipeline in terms of monitoring corrosion and erosion factors, as well as managing water, chemical usage or various location-based HSSE metrics. The MAPS tool is not limited to well or pipeline performance, but capable of locating and tracking field personnel and mobile equipment for managing field activities such as maintenance, drilling, equipment surveillance, or emergency evacuation. What began as a concept has now expanded into a robust visualization and modeling application which is expected to grow across other BP assets as part of FIELD OF THE FUTURE roadmap.
Laboratory Investigation of Influences of Initial Oil Saturation and Oil Viscosity on Oil Recovery by CO2 Miscible Flooding
Authors: Shedid Shedid A. , Zekri Abdulrazag Y. , Almehaideb Reyadh A.
Published: December 2007

Miscible carbon dioxide flooding is an effective method for Enhanced Oil Recovery (EOR). The main objectives of this study are to investigate the influences of mobile oil saturation at the start of CO2 flooding and reservoir oil viscosity on oil recovery by CO2 miscible flooding. Actual fluid and rock samples used were obtained from a field under development in the U. A. E

To achieve the objectives of this study, six core-flooding experiments were performed using supercritical CO2 slug size equivalent to 0.15 hydrocarbon pore volume (HCPV) under simulated reservoir conditions of pressure and temperature. Five experiments were performed under different mobile oil saturations in the range of 32.74 % (i.e. after complete water flooding) to 79.43 % (with no water flooding). The sixth run was applied using heavier crude oil viscosity. All flooding experiments were carried out using actual core samples extracted from the field and flooded using actual reservoir fluids.

The results indicated that the earlier the start of CO2 miscible flooding the higher the oil recovery. The start of CO2 flooding with the core saturated with oil at irreducible water saturation produced 98.61 % IOIP while flooding with CO2 after complete water flooding recovered 83.31 % IOIP. Furthermore, the increase of oil viscosity decreased the oil recovery by CO2 flooding. The injection of the same CO2 slug size produced 98.61 % IOIP for oil viscosity of 1.03 cp while the same application recovered only 86.11 % IOIP for heavier oil viscosity of 2.62 cp.

The main conclusion drawn from this study is that while the application of CO2 flooding has successfully recovered more oil either after water flooding or as a secondary process, the application at initial oil saturation recovered the maximum oil recovery.
Case History: Acid Stimulation Devonian Horizontal Wells
Authors: Swain Michael , Nordstog Kim , Miller Howard , Weaver Bob , Metcalf Arthur S.
Published: December 2007

In the Arbol De Nada Field in Ector and Winkler Counties of Texas, there are 29 producing wells in the Devonian. Recently several horizontal wellbores have been added to the field. Five of these are newly drilled and have been completed with uncemented liners and openhole packers for isolation. Between each of these packers is a sliding sleeve to facilitate stimulation. The Devonian has a limestone, dolomite and chert composition which makes acid fracturing the method of choice for stimulation.

Given the open annular space between the packers, zonal coverage is dependent upon rate and fluid choices. Presented are the results of stimulation work on these horizontal wells. Included is a discussion on rates and fluids chosen. Production responses are also presented in comparison to the vertical completions.
Case History: Acid Fracturing Deep, Hot Ellenburger
Authors: Swain Michael , Nordstog Kim , Miller Howard , Fallon James , Weaver Bob , Metcalf Arthur S.
Published: December 2007

In Val Verde and Crockett counties of Texas, operators are drilling 15,000 feet plus wells to produce the Ellenburger formation. Bottomhole Static Temperatures are in the neighborhood of 320°F. Since the Ellenburger is a massive dolomite formation with natural fractures the optimum stimulation method is acid fracturing.

Discussed are the critical issues to achieve a successful stimulation using acid at plus 300°F. In addition, techniques employed will be reviewed. One technique is stimulation in a single treatment using ball sealers for diversion and CO2 for load recovery. A second method is to break up the large interval into smaller segments treating and isolating with plugs. The third technique employs packers and sleeves with CO2 for load recovery. The production results from these techniques are compared.
An Integrated Geological and Engineering Assessment of Fracture Flow Potential in a Middle-East Carbonate Reservoir
Authors: Whitaker A. E. , Kabir C. S. , Narr W.
Published: December 2007

The extent to which fractures affect fluid pathways is a vital component of understanding and modeling fluid flow in any reservoir. We examined a Lower Cretaceous grainstone for which production extending over 50 years, including recent horizontal drilling, has provided some clues about fractures, but their exact locations, intensity and overall effect have been elusive. This study attempts to discern open fractures, if any, and their locations to facilitate building next generation earth and flow-simulation models.

The geological assessment involved mapping fault orientations from seismic and analyzing image logs and cores for fractures. Fracture trends are in the NE and SW quadrants and fractures are mineralized toward the south and west of the field. Pressure falloff tests on some peripheral injectors indicate partially sealing faults. Most of these wells lie on seismic-scale faults mapped in the reservoir. Some wells show fractured-reservoir production characteristics and rate-transient analysis on a few producers indicates localized dual-porosity behavior. Producers proximal to dual-porosity wells display single-porosity behavior, attesting to the notion of localized fracture response. The spatially-restricted fracture signature may be owing to fracture or vug zones, or to low-permeability reservoir.

Presence of fractures was discerned by constructing the so-called flow-capacity index (FCI), which is the ratio of khwell (welltest-derived value) to khmatrix (core-derived property). Data from 80 wells showed khmatrix to be consistently higher than khwell, with the p-50 reciprocal-FCI being 13, a relationship that suggests insignificant fracture production in these wells.
New Cleanup System for Gravel-Pack Completions: A Synergy of a Unique Acid System and Special Rotating Jetting Tool
Authors: Aguiar Jacqueline , PorDeus Jefferson M. , Almeida João B. , Melo Ricardo C. B. , Aboud Ricardo S. , Duque Luis
Published: December 2007

Gravel packs completions are widely used today on unconsolidated formations worldwide, as to provide sand control, and, as such, behaves as a filter. A filter is subjected to be plugged by fines, (heavy) hydrocarbons, scale depositions, among others, which may result in a considerable drop of production, or even total lack of.

The synergism of coiled tubing rotating, cyclical jetting tools, and adequate acid systems has demonstrated great results in Northeast of Brazil. The cyclical jetting tool acts to disaggregate plugging particles from the gravel, and the acid acts to chemically dissolve acid soluble plugging materials.

The acid system utilized is quite unique and simple. The method consists of pressure cyclically jet solvent and a small amount of a specially designed acid system, to clean up the gravel pack. No acidic flushes are used ahead or after the acid system, because the acid system is a high pH one (2 – 3), and uses an organophosphonic acid to control the dissolution of carbonates, and, therefore, controls the precipitation of insoluble fluorides. This way, release of calcium ions is less likely to occur. The main acid system is hydrofluoric (HF) based, generating HF on a controlled fashion, using much less hydrochloric acid (HCl) when compared to regular HF acid systems.

This paper describes three gravel packed wells treated with this single step acid system. These wells were very similar, and used the same acid recipe However, the first well was treated with a rotating pressure cycle jetting tool, and the remaining two wells used a different pulsation tool. All wells showed production increase, but the first well yielded much better results compared to the last two. Results from these three treatments will be presented and compared as towards the effectiveness of coiled tubing tools deployed.
Subsidence Due to Fluid Withdrawal in Fractured Reservoirs
Authors: Atashbari Vahid , Ahmadi Mohabbat
Published: December 2007

Land subsidances around the world and also several casing collapses in some fields of Iran, in drilling and producing time, and also in the period of no production, emphasis the rule of geomechanic factors, the overview of Geomechanical studies of fractured reservoirs.

It's clear to predict subsidence (rock compressibility) in sandstone rocks, and some of the professional experts have been worked on it, but about the fractured reservoirs, there are some differences. Regarding to the depth and size of fractured reservoir, in most cases there is no evidences in the surface related to compressibility of underground producing formation, that's why many of petroleum engineers neglect it, so they don't study it in the modeling and reservoir management while some of downhole assemblies problems are related to the pore pressure decrease, porosity loss and in some cases fault activation were caused by subsidence.

And we will show in this paper that Subsidence occurs in the Fractured reservoirs and beside the damages, petroleum experts can use it to increase recovery rate of oil and gas.
A Review on Microbial Enhanced Oil Recovery With Special Reference to Marginal/Uneconomical Reserves
Authors: Zahid S. , Khan H. A. , Zahoor M. K.
Published: December 2007

Oil and natural gas are vital for any economy and the importance of these resources in determining the social stability and economic viability of a nation is enormous. As the search for petroleum continues, recovery of known reserves must be improved if the goal of avoiding shortages is to be met. In today's energy sector, the high oil prices have driven the oil companies to recover the maximum amount of oil with the lowest production costs. Thus, economic production of oil and gas resources requires carefully engineered recovery projects of increasing technical complexity and sophistication.

One of the promising recovery methods is the microbiological enhanced oil recovery (MEOR). MEOR technology has the potential to be one of the reliable technologies that suits best the economic constraints of the current oil markets. The technology is a potential alternative to other EOR/ IOR methods, as it is being implementing in most parts of the world with satisfactory results not only form economics point of view but also from having lesser environmental impact.

The paper provides a review on MEOR technology and discusses it with special reference to marginal and/or uneconomical reserves. The goal of cost reduction, which is a major objective in any recovery methods, can be met by using MEOR technology which involves injecting a small amount of a solution containing microorganisms to spread through the reservoir and consequently produce desirable chemicals and gases that will enhance oil recovery and therefore profit. The paper also outlines the strategies to identify and meet the challenge of recovering large proportions of oil using MEOR techniques which could be very helpful in closing the energy gap by draining large proportions of oil which is left behind and minimizing the supply and demand difference in today's "energy hungry world".
Calculation of Flowing Optimum Bottomhole Pressure Constraint Based on Bubblepoint-Pressure-vs.-Depth Relationship
Authors: Obeida T. A. , Mosallam Y. H. , Al-Mehairi Y. S.
Published: December 2007

Thick reservoirs usually have variations of PVT properties such as bubble point pressure and dissolved gas oil ratio with depth. A considerable effort usually spent to describe such properties to be used in dynamic models either in Black Oil or compositional simulators. However, during predictions many dynamic models set the BHP constraint as a constant value for all producers in the entire reservoir regardless of perforations depth. Usually this constant value is close to the average bubble point pressure or a little higher to ensure single phase (oil) production and not considering changing of bubble point pressure with depth.

The above procedure introduces uncertainty regarding well potential, which involves a risk of not presenting accurate well performance in the simulator and would impact oil production and recovery forecasts.

The proposed method was developed to calculate following BHP constraint based on bubble point pressure versus depth relationship for each grid cell in the dynamic model, thus creating 4D-array (I, J, K, BHP constraint) for the entire reservoir.

The proposed method is fully automated and tested to assign BHP constrains in schedule section of huge dynamic model (2.6 million cells) with 600+ wells.

Two prediction cases were tested (each case run twice, one run with constant BHP constraint for all the produces and the other one using variable BHP constraint recommended by the proposed method) to evaluate the impact of BHP constraint on production and oil recovery forecasts.

The results of these two runs showed a considerable difference in length of oil production plateau and oil recovery forecast, but negligible differences in gas oil ratio.

The proposed method could be used for any dynamic model with vertical and/or horizontal variation of bubble point pressure to calculate an optimum BHP and thus WHP to maximize production rate without the risk of introducing gas phase at reservoir conditions.
The Effect of Positive Coupling and Negative Inertia on Deliverability of Gas Condensate Wells
Authors: Carvajal G. A. , Arreaza E. , González C. , Cesin C. , Fernández M. , Bello J.
Published: December 2007

Most of the cases in gas condensate wells produce below dew point pressure generating a saturated zone in liquid that blockage the gas flow efficiency to the well. Not only is the gas well productivity affected by fluid but also velocity. The conventional theory to analyze the phenomena associated at rate dependent is commonly interpreted using Isochronal or flow-after-flow tests. After this test, the negative impact of inertia on gas deliverability can be very well analyzed using special graphics. However, the actual effect related to capillary number and its dependency with velocity, called Positive coupling, is not yet analyzed in transient tests. As it has been mentioned in literature, the effect of coupling over gas condensate wells improves the pair of krg and krc and minimized the effect of skin rate dependent.

Flow-after-flow tests of 6DD+1BU have done in gas condensate wells in the Monagas Field, Venezuela. The results have shown that the wells in this field produce under the Non-Darcy flow regime and that its deliverability is decreasing due to condensing banking and the effect of inertia. Nevertheless, the flow-after-flow test revealed that, inertia is important at lower rate when a liquid saturation is significant but positive coupling becomes more important at higher rate. As a result, an increasing of condensate liquid rate and an optimization productivity point has been obtained.

This paper presents a methodology to analyze the Non-Darcy effect and to observe the competition between inertia and coupling. The most important contribution of this work is that gas well deliverability forecast can have a best estimation and a new developement plan can be proposed for a full field case. According to this test, the gas well productivity can be improved with the sense of recover more liquid of condensate.