bluuebunny/crossref_metadata_2025_split huggingface dataset:
Forecasting Reservoir Management Through Integrated Asset Modelling
Authors: Ursini F.. , Rossi R.. , Pagliari F.. 
Published: February 2010

Abstract
The main challenge of Integrated Asset Modelling (IAM) is to couple dynamic reservoir and surface facilities models into a single integrated tool that allows the simulation of the whole oil field system. It is possible to take into account the following issues in a realistic way: pressure interactions between surface and subsurface, identification of system bottlenecks and backpressures, the system constraints, the mixing of different fluids and flow assurance.
An integrated asset model has been developed for an onshore Algerian asset which comprises three oil reservoirs connected through a surface network system to the same plant.
The controller program used for the simulation is Resolve, by Petroleum Expert. It enables the integration of the network model (GAP) and the reservoir models (Eclipse).
The results of the simulations show that IAM is able to reproduce the current field production data with an acceptable accuracy. Therefore, it can be used for forecasting purposes in order to evaluate different scenarios in terms of production rate and final oil recovery.
Two different IAM scenarios have been evaluated: constrained and unconstrained by a maximum oil production rate. The results have then been compared with the field behaviour simulated with the stand alone Eclipse models. The analysis of the IAM approach effect on the production profiles with or without the maximum oil rate constraint demonstrates that the integrated Asset Model is a powerful tool providing useful guidelines for field management in addition to a greater accuracy in the production forecasts and final oil recovery.
Improving Deep-Well Economics with Foamed-Cementing Solutions
Authors: El- Seginy Ahmed , Atta Abdel Azim , Kashif Omar , Zanaty Akram , El Sawah Khaled , Waheed Arshad 
Published: February 2010

Abstract
The practice of deep-well drilling (i.e., reaching depths of 15,000 ft or more) has been increasing for more than three decades with well costs increasing as record depths are continually challenged. The demand for gas has generally supported this drilling activity, nevertheless the pursuit for drilling the most economical well continues. This paper presents a case history of cementing a long, intermediate casing string. Such casing strings are strategically placed covering a large section of the drilled hole straddling as close as possible between the lowest fracture gradient and the highest pore pressure in the drilled section. Such a design helps minimize the number of casing strings required for the well, thus helping to reduce the well cost. While it might be possible to drill the hole by maintaining a balancing act between flow and loss situations, the cementing challenges remain to be tackled.
The use of foamed cementing has addressed the issue of cementing in a lost-circulation situation and controlling the flow from a gas zone found within the same interval. When compared to conventional cement jobs, foamed cement was not only superior in technical design but provided several cost-saving benefits that many potential users might be unaware of. For example, the bulk cement-volume requirement dropped by a factor of 1.72, provided a cost saving of approximately 35 to 40%, and reduced the bulk equipment footprint from 1,560 ft2 to 936 ft2. The job-time also decreased by three hours. These discrete savings combined are significant.
Though this solution brings much benefit to operators, it is still regarded as an unconventional cementing solution. This paper provides a case history, economic analysis, physical properties, and developmental background of foamed cementing that should help operators see its benefit and use.
Innovative Application of Foamed Cement for Zonal Isolation of a Tieback Casing across Highly Corroded Casing
Authors: de Weerd Arie , Al Hanshi Salim , Al Aghbari Salim , AlFadhli Abduallah 
Published: February 2010

Abstract
Drilling a surface hole with total losses through shallow aquifers is normal practice in Oman and most of the Gulf region. If losses cannot be cured while drilling, and the casing cement does not return to surface, required zonal isolation is most likely being compromised.
During the life of the well, flow behind the casing from the shallow aquifers results in accelerated casing corrosion that compromises the integrity of the well and results in relatively costly workover operations to restore the well and allow it to be operated.
Squeeze cement that repairs each corroded section of casing is a relatively high-risk and expensive operation with a low chance of success.
During a workover on one of the water-injection wells in North Oman, severely corroded 9 5/8-in. production casing was confirmed. The initial investigation confirmed multiple leaks in the 9 5/8-in. casing, of which the exact location was difficult to establish; however, it was expected to have resulted from a failed 13 3/8-in. surface casing caused by corrosion from the shallow aquifers. Communication between the 9 5/8-in. production casing and the 13 3/8-in. surface casing was confirmed in multiple zones. Different options were evaluated to restore the integrity of this well. The options evaluated included the use of mechanical casing clads (expandables) to fix each corroded section in the 9 5/8-in. production casing before running a 7-in. cemented tieback string and the option to squeeze cement across each corroded section in the 9 5/8-in. production casing before running a 7-in. cemented tieback string. Both of these options were abandoned because of economic concerns and low chances of success. It was decided to approach this integrity repair differently by running a 7-in. tieback casing to surface and using foamed cement to cement the 7-in. tieback casing and existing corroded 9 5/8-in. casing to surface. To maximize the chance of success, the 7-in. tieback casing incorporated a multistage cementing collar to help ensure foamed cement returned to surface. The two-stage, foamed-cement job with controlled returns from two annuli might be considered to be the first of its kind, globally. The foamed-cement job was executed successfully as per program, with good foamed cement returns from both the 7-in. × 9 5/8-in. annulus and the 9 5/8-in. × 13 3/8-in. annulus. The overall job met all the objectives and this technique has been repeated successfully on subsequent wells with similar integrity issues.
Evaluating Steam Injection Profile with High Temperature Memory PLT
Authors: Samir Mohammed , Hassan Wael , Kamal Salah , Hassan Amr , Draz Mohamed , Waheed Arshad 
Published: February 2010

Abstract
The Issaran field, a heavy oil reservoir with estimated original oil in place (OOIP) of approximately 1.6 billion bbl of oil, was discovered in 1981. The producing horizons are the carbonate formations of Miocene age occurring from depths of 1,000 to 2,000 ft. The oil is of 9 to 12 °API with viscosity of 4000 cP at standard conditions. It was not until early 2000, after the crude oil prices rose to favorable levels, that a concerted effort was made to develop this heavy oil. Cold production from the fractured carbonate Nukhul reservoir (depth approximately 2,000 ft) was first targeted and the production from the field increased from 170 barrels of oil per day (BOPD) in 1998 to more than 2,300 BOPD in 2002. However, the Upper Dolomite reservoir, at a depth of 1,000 ft, held more than 50% of the OOIP, but did not produce.
Subsequently, a pilot project using cyclic steam injection was implemented on two openhole completions in the Dolomite reservoir and the production results far exceeded predictions, proving it to be commercially viable. This pilot scheme was expanded to two, seven-spot pattern wells and the total combined production from the Issaran field reached 5,000 BOPD in late 2008. Recently, however, the productivity of the Upper Dolomite wells has declined. The water cut has increased and the steam injection efficiency is becoming questionable.
Because the steam temperatures of nearly 600°F exceed the operational limits of conventional production logging tools (PLTs), they cannot be used for steam injection profile monitoring. In addition, wellhead control and operational safety concerns become challenging issues. One effective solution to the problem was to run high temperature Memory PLT (MPLT). These tools are built for high temperature service and can be run on slickline, making this a more cost effective solution. The three wells selected for the preliminary run of the MPLT service were also the first applications of this technology in the Middle East area.
The primary results have already shown deficiencies in the steam injection process because most of the steam is being preferentially injected into water-bearing zones. This paper provides a detailed review of the results from the PLT surveys and the completion strategy implemented to improve productivity and maintain project profitability.
Pore Pressure Prediction and Pressure Regime Evaluation, Role and Contribution in Well Planning and Formation Evaluation Process, Gulf Of Suez Oil Fields – Egypt
Authors: Moustafa Selim Saber , El-Sayed Badawy Bassem , Mohamed Abdullah Khaled 
Published: February 2010

Summary
The study aims to construct a simple and effective pressure regime model for Zeit Bay Field (as an example of one of Gulf of Suez Oil Fields which has a complex reservoir), which can assist the well planner to predict the pore pressure for the upcoming wells to be drill in the field. It aims also to find out the relationship between the constructed pressure regime model and the geological setting of the field.
Deepwater Drilling in Both Hard and Abrasive Formations; The Challenges of Bit Optimisation
Authors: Murphy Dominic , Tetley Nick , Partin Uyen , Livingston Denise 
Published: February 2010

AbstractIn mid 2007, two deepwater exploration wells made the first significant oil discovery offshore Ghana, West Africa (Jubilee Field). Drilling of the first two wells and subsequent appraisal wells indicated hard and abrasive formations, notably in the 12-1/4" reservoir sections, where up to four bits were needed using a combination of polycrystalline diamond compact (PDC) and tungsten carbide insert (TCI) bits. Therefore amongst the many project challenges there were significant drilling challenges to overcome. The primary goal was to drill the 12-1/4" section in one run, with the benefits of substantially reducing drilling time and costs where full-spread operating rates are in excess of $1MMUSD/day.To address these challenges, the drilling team adopted a holistic planning approach prior to drilling the first development well. This used, in conjunction with a detailed analysis of the offset performance, a 4D finite element model that accurately predicts the performance of bit and bottom hole assembly (BHA). This approach allowed a fundamental understanding of the proposed system and its behaviour. The goal of drilling the section in one run was achieved far sooner than would have been expected using "trial and error" methodology, but with high vibration levels. Ongoing optimisation of the dynamic model with the actual down-hole data justified a BHA change to reduce vibration levels. Subsequently, the changes made to the BHA successfully reduced vibration levels, more than doubled rate of penetration (ROP) and facilitated good quality log while drilling (LWD) data.With the high cost base of deepwater drilling activity, optimisation solutions that can be applied before and during the drilling process will make significant contributions to the overall project economics. Efforts were therefore applied to making the best pre-well bit and BHA selection, then analysing and understanding initial results, with an emphasis on maximising any learning and incorporating recommendations into the subsequent well. On the Jubilee Project, on-going optimisation can now focus on maximising overall drilling performance.
New Acid-Diversion Technique Helps Stimulation of Production and Injection Wells—Case Histories from Egypt
Authors: Hamdy Mostafa , Taha Islam , Waheed Arshad , el Masry Yasser , El Eraky Hesham , Hanafy Khairy 
Published: February 2010

AbstractOne of the critical measures of success in matrix acidizing is having the acid distributed across all the zones of interest, thus ensuring they are all stimulated. This applies to production and injection wells where most zones are not homogeneous in terms of permeability, porosity, water saturation, or the degree of damage they have experienced; therefore uniform distribution of acid during the acid job is seldom achieved. For producing wells, this task is further complicated when high water-saturation zones form part of the pay interval; not only do the producing zones get inadequate stimulation, but the water zones get preferentially stimulated to produce large quantities of unwanted water that can kill the well or increase the lifting and disposal costs for the well.Many acid-diversion techniques, mechanical and chemical, are available to help achieve even distribution of acid, but addressing water control and stimulation of the preferred zones in one treatment is uncommon. A new acid-diversion technique using associate polymer technology (APT) applied in the western-desert region of Egypt achieved tremendous results when compared to similar wells treated in the area. In one case, the production results from the well treated with APT were as high as 5,000 BFPD with negligible (0.02%) water cut compared to another well that produced similar fluid quantities, but with more than 50% water cut.This paper discusses the first use of APT technology in the Al-Amein dolomite reservoir of Egypt and compares it with the earlier uses of other diverting methods in the same field. This same diversion technique was also recently used in another carbonate reservoir Abu Roash "G" (in the same field) on an injector well and it improved its injectivity index eight-fold. These successful stimulation case histories from the two reservoirs are elaborated in this paper.
Relative Permeability Modifier Fracturing Technique Inhibits Post-Fracturing Water Production: Case Histories from Egypt
Authors: Ali Ahmed , Yassine Rami , Waheed Arshad , Aal Ezz Abdel , Monsef Mohamed Abdul 
Published: February 2010

Abstract
Hydraulic fracturing has been extremely successful in the western desert of Egypt, with approximately 85% of the production resulting from the use of this stimulation technique. However, in many cases, the proximity of producing zones to underlying (or overlying) water zones can be a deterrent to fracturing. In the absence of geological barriers, the fracture height can grow uncontrolled during a fracturing treatment into the water-bearing interval and cause unwanted water production. By shortening the well's production life and increasing disposal and lifting costs, excessive water production can be extremely detrimental in marginal fields.
This paper presents case histories in which wells were hydraulically fractured using conventional techniques, resulting in higher than 60% water cut, and even as much as 100% in one case. While using the conformance-while-fracturing (CWF) method, the water cut was as low as 4%, even when the adjacent water zones were within 20 ft of the perforations. This technique provides a tremendous boost to the economics and an effective solution to a field otherwise plagued with water overproduction. The CWF technique incorporates a relative permeability modifier (RPM) in the fracturing-fluids design. The RPM results in a reduction of effective permeability-to-water without significant changes to the relative permeability-to-oil. This paper discusses the properties of the RPM, the CWF job-design considerations, its field applications, and post-fracturing results in comparison to offset wells fractured conventionally. These techniques might be beneficial to other companies faced with similar water-production challenges.
A New Criteria to Predict Stuck Pipe Occurrence
Authors: Meschi M. R. , Shahbazi K.. , Shahri M. Pordel 
Published: February 2010

Abstract
Stuck pipe is one of the main problems in drilling oil and gas reservoirs. It usually occurs in high pressure wells and leads to tremendous delays and costs in Iran, every year. Even if different techniques and guidelines have been developed to reduce the probability of occurrence of this phenomenon and these have saved drilling industry millions of dollars, they suffer from exclusive prediction of this event. The reason is that some of these techniques such as sag register incorporate one drilling parameter such as mud weight only.
In this paper, mud logging and daily reports of 75 wells in one of Iranian Southwest oil fields were studied. The performance of wells that did not experience stuck pipe was compared with the performance of those that led to stuck pipe.
Mud weight, yield point, plastic viscosity, initial gel strength, Marsh funnel viscosity, dial reading at 600 rpm, solid content, temperature, washout and the period that pumps do not need maintenance were employed to introduce a new parameter called Reducing Stuck Index (RSI). It was found that RSI is proportional to the mud weight, initial gel strength; yield point, solid content and temperature and also inverse of plastic viscosity, Marsh funnel viscosity and dial reading at 600 rpm to the power of 0.3. For this field, the comparison of RSI of the current well with those of drilled wells predicted the probability of occurrence of stuck pipe very well.
Monitoring RSI helps the driller to know whether the drilling process results in stuck pipe. If the situation is leading to stuck pipe, the drilling parameters can be managed in such a way that RSI lies in the safe range and stuck pipe is prevented.
Formation Damage Kinetics and its Effect on Oil Reservoir Productivity
Authors: Mikhailov N.. , Chirkov M.. 
Published: February 2010

Abstract
Formation damage, a common problem associated with field operations, is often a major factor in reducing the productivity and injectivity of a well in a petroleum reservoir. Numerous laboratory and field studies indicate that formation damage occurs during many phases of reservoir development – drilling, completion, workover, production, stimulation, water flooding, or improved oil recovery. Formation damage is a process of initial permeability reduction. At present many mathematic formation damage models are developed. These models contain a number of parameters that is difficult to determine and mostly are not appropriate for field usage. We offered a way from lab to field scale that takes into account the process of formation damage during reservoir development. Analyzing the results of laboratory experiments and formation damage studies we defined that permeability has similar kinetics of alteration for different damaging mechanism. Next we determined the principal damaging mechanisms of real oil formation and associated them with laboratory relations of permeability alteration. As a result the integrated relations of permeability reduction and the new model of formation damage were obtained. This method was used as a predictive tool for quantitative predictions of field development showings for different rock types and operation strategies. Equations of permeability kinetics were integrated into reservoir simulator. The effect of permeability kinetics on formation development process was shown concerning clay oil formation. Based on laboratory and field observations the methods of enhanced oil recovery and formation damage prevention were proposed.
Characterization and Simulation of a Complex Fractured Carbonate Field Offshore Tunisia
Authors: Bejaoui Riadh , Salem Ryadh Ben , Ayat Hamed , Kooli Imen , Balogh Dave , Robinson Gary , Royer Theodore , Boufares Taoufik , Ouenes Ahmed 
Published: February 2010

Abstract
This paper describes a workflow that fully utilizes the pre-stack and post-stack seismic attributes to derive reliable geologic and fracture models that are validated by multiple blind wells and reservoir simulation. The first step in the workflow is to run post-stack seismic processes, which includes post-stack inversion and spectral imaging. The second step consists of applying a pre-stack seismic process called elastic inversion which will lead to various key seismic properties that provide good discrimination between reservoir facies. The third step consists of using the various post-stack and pre-stack seismic cubes to derive 3D geologic and fracture models. The fourth step is to use the derived models in a reservoir simulator to verify the validity of the models.
This workflow was applied to a complex fractured carbonate field in offshore Tunisia which produces oil from the El Gueria formation. A large number of post-stack and pre-stack seismic attributes were generated in time and then depth converted within a 3D geocellular grid. These seismic attributes were used as input in REFRACT™, Prism Seismic fracture modeling software, to create geologic and fracture models. The resulting porosity and permeability models were put into Eclipse™ reservoir simulator software. Individual well performances were matched at eighty percent of the wells, confirming the reliability and accuracy of the derived geologic and fracture models and the usefulness of the workflow.
The First Successful ImpulseTest on Coiled Tubing Results in Reliable Reservoir Evaluation for Non-naturally Flowing Wells
Authors: Guichard Anna , Zhan Lang , Dilling Lambert , Giaquinta Alejandro , Mohamed Ezz Eldin , Awaad Ahmed Hamdy 
Published: February 2010

AbstractIn mature fields it can often be a challenge to obtain accurate well data and reliable formation parameters without imposing high cost and time constraints on development or production schedules. One common method to test non-naturally flowing wells is impulse testing, which makes use of differential pressures between the formation and a surge chamber or wellbore to perform a short flow period or surge test, followed by a relatively short shut-in period. Unfortunately, these tests frequently result in invalid or uninterpretable data as a result of several uncertainties and test constraints.An improved version of this common technique encompasses a three-fold approach to optimize the impulse test. A new numerical simulator designs the test to maximize depth of investigation without compromising the interpretable data. The coiled tubing-conveyed intelligent bottomhole assembly used to execute the impulse test may, in certain environments, reduce operating times in comparison to use of conventional tubing-conveyed solutions. The combination of the prejob design package and a functional bottomhole assembly enables consideration of the complexities that can result from impulse testing so that a valid data set is delivered. The interpretation is performed using traditional well test interpretation methodology and an analytical solution specifically designed for impulse testing. This solution considers the wellbore fluid density variation during the test while still maintaining the simplicity of the wellbore model; variable skin is described by an exponential function, thus improving on established analytical methods. A comparison of the results from both interpretation methods establishes the test validity in terms of flow capacity and skin. This paper describes the systematic approach, including its design, execution, and interpretation, and highlights advantages and limitations through the case study and field data of a well in the Wadi Rayan field of Qarun Petroleum Company.This technique offers a rigless testing method that can optimize test time while delivering valid, accurate results that aid in production forecasting, completion optimization, and planning of remedial intervention for non-naturally flowing wells.