Multiphase pressure drop calculations represent a challenge for petroleum engineers. We normally rely on multiphase flow correlations to calculate pressure traverses through tubing from the sand face to the wellhead. Although there are many multiphase flow correlations covering most flow conditions; there are still no clear criteria to select appropriate correlations in absence of flowing gradient survey data. The objective of this work is to help petroleum engineers select the most accurate multiphase flow correlation(s) for any flow conditions, fluid properties, and well configuration. The method depends on analyzing a large database of pressure drop data from many wells. Our database is composed of more than 3,200 measured pressure points taken from survey and single point measurements on 879 wells representing large variations of flow conditions (oil rate ranges from very low rate to 31,000 BBL/D, water cut from 0 to 98%, gas-oil ratio from 0 to 20,000 SCF/STB, gas rate from very low rate to 200 MMSCFD, water gas ratio from 0 to 200 BBL/MMSCF, condensate gas ratio from 0 to 200 BBL/MMSCF for vertical, deviated and horizontal wells with different tubing sizes). We built models for all these wells and tested many available multi-phase flow correlations and recorded the error in their prediction against the actual measurements of pressure points. We then classified the large database into groups and found all multi-phase flow correlations within this group that have the lowest error. For every group, we can now identify the best correlation(s) with their estimated error value. We also defined a term to reflect the strength of the appropriate correlation(s) (how many times this particular correlation was best in each group of data) to help engineers select appropriate correlation for each well and its flowing conditions. The strength term for all groups varies from 100 % to 30% which indicates that for several groups we can now select the multiphase flow correlation with significant accuracy. The expected error for all correlations is also reported. The parameters that mostly affect each correlation are also highlighted so engineers would know which parameters need to be accurate in using the recommended correlations.

Gas lift is one of the artificial lift techniques which it is frequently implemented to raise oil production. Conventionally, the oil wells produce depending on the energy of reservoir pressure and solution gas which declines due to continuous production. Therefore, many oil wells after a certain production time become unable to lift oil to the surface. Thus, the continuity of production requires implementation of gas lift which works to decrease the average fluid density in the tubing by injection gas through the annulus into the tubing. This paper aims to get maximum oil production of an Iraqi giant oil field at optimum injected gas rate. The field is located in south of Iraq and includes 67 wells. In this paper, new model is designed to matching PVT data, matching vertical pressure drop calculations, making sensitivity analysis of wellhead temperature variation, making sensitivity analysis of productivity index variation, achievement of optimum design of gas lift and finding optimum values of oil production and injected gas rate. The gas lift design is implemented within two cases. The first case aims to get the maximum oil production using flowing bottom hole pressure cut off as 50 psi above the bubble point pressure at certain depth. Whereas in the second plan, the same cut off value is maintained while keeping the injected gas oil ratio below or equals 350 SCF/STB. The two constraints are applied according to the policy of the operating company for the field under study. This results show the implementation of the gas lift technique can increase oil production from 64379 STB/D to 302712 STB/D in the first case and to 272359 STB/D in the second case. In addition, 45 ceased wells were brought to production by implementation of the gas lift. The model predicts that the required injected gas rates to produce the new production are 186.3 MMSCF/D and 74.606 MMSCF/D in the first and second cases respectively. The main conclusions lead to the application of gas lift technique for this reservoir can increase the oil production volume significantly.

Dragon Oil needed to extend the production lifecycle for it's offshore field wells with lower than expected natural flow regime duration. After reviewing multiple of running the Electrical Submersible Pumping options, Dragon Oil chose to implement tubing conveyed and rigless ESP's to return the candidate wells to the required production levels. This case study highlights the technological rational, challenges in implementing decided strategy and prognosticates expected results & benefits from running the two types of ESP's as an additional well investments. Candidate wells for ESP Artificial Lifting have been drilled from offshore wellhead platforms “1” and “2” into the flanks of the Main Field Reservoirs. Commissioning of the pilot ESP projects is expected by end of 2015.

Dipmeter & image logging tools had gained wide acceptance in petroleum industry as a mean to define subsurface sedimentary structures and to detect geologic signatures of tectonic events. The advantage of dipmeter & image logging, over seismic is that they rely on their ability to provides accurate information's near the well bore and detect structural features beyond seismic resolution. Dipmeter & Imaging information in frontier areas with poor seismic imaging (scattered 2D seismic data over thrust & belt regime) is paramount from wildcat spud, mainly to initially correlate with surface geological data, later on constantly update the geological model and, of course, to visualize expected geological prognosis for the undrilled section. In the Kurdistan region (Iraq) usually the surface sections are drilled with air/foam air due to existing drilling risks. An operational imposed mud system that triggers several limitation from the data acquisition point of view. In this case the Joint Venture (Repsol Exploration as an Operator and Maersk as a partner) decided to use a High Definition Formation Micro Imager as a challenge against the lack of other wireline logging reliable tools (Sonic, etc…). Initially this High Definition Formation Micro Imager with its high vertical resolution of 0.2”, was designed electronically for greater reliability and clearer images in extreme conditions, could provide an excellent image in Air/Foam mud. This tool data revealed that the dip patterns over the intervals suffer from increasing and decreasing of dips downward with repeated azimuth directions (generally from NE to SW). These changes were not accompanied by any fracture displacement (faulting). These zones were interpreted due to the presence of series of recumbent and overturned folding, where the direction of dip decreases till the axial plane of the structure, then increasing again towards the opposite flank with different azimuth direction. This interpretation helped matching the updated geological model (unexpected recumbent & overturned folding) with the surface geology, and determined a startup (geological prognosis) for the undrilled section. This paper documents that a High Definition Formation Micro Imager can be successfully acquired in such tough Air/Foam mud conditions. It also provided reliable downhole information for surface section project decision. This data proved to be very important to update the geological model and provide a required geological prognosis.

The Gulf of Suez Petroleum Company (GUPCO) is a leading Egyptian petroleum company. GUPCO production is primarily dependent on gas lift with 90% of its producing wells utilizing this artificial lift method, consuming more than 450 MMSCF of gas per day. One of the main hindrances to maximizing GUPCO's production is insufficient gas supply which leads to shutting in many producers resulting in significant production deferrals. GUPCO's Base Management Team (BMT) initiated an integrated system optimization project in 2013 which combined four different technical pieces of work. It was introduced for the first time in GUPCO to ensure gas is used efficiently in the Gulf of Suez (GoS) to maximize the value of GUPCO's old data, build trust in well and surface modelling and increase BMT capabilities. The main challenges of this project were data gathering and quality, engineering capabilities in the use of Prosper and GAP modelling and lack of integration between field and office technical personnel regarding the system optimization. Working through these challenges created tangible value through enhanced understanding of the gas sy stem, identifying additional opportunities to save gas and increased oil production. This boosted the modelling capabilities of all team members. The BMT approach was divided into four different phases as follows: Gas balance study for better understanding of the gas systems in the different areas across the GoS. Prosper modelling for gas-lifted wells that resulted in 20 gas lift valve change opportunities that lead to increased production of 1000 BOPD. GAP modelling for the production system that resulted in a 7700 BOPD potential oil gain, 16.5 MMSCFD potential gas saving and debottlenecked pipelines. Creaming curves which became a very good tool to prioritize the GL wells with respect to gas availability, evaluating well work value, and quantifying the impact of surface facilities failures and/or repairs. Until the time of this paper, the project was in the execution phase and has resulted in saving 7 MMSCFD from optimizing gas lift injection in 8 wells. The forward plan of the project is as follows: Continue the execution phase and ensure good communication between all teams. Install recommended meters/scanners to enhance data measurement in order to ensure sy stem balance. Complete GL optimization execution in SC GoS & share the outcomes. Install MPFM on some offshore platforms which will help in evaluating the optimization. Utilize a Portable Test Package for further enhancement of system evaluation & optimization. The objective of this paper is to show the technical processes used to initiate an integrated gas lift optimization project in the GoS and how the opportunities created will add considerable benefits to the business.

Horizontal and highly deviated wells are increasingly being used in oilfield developments worldwide. Large-bore horizontal wells can deliver significantly higher oil production rates than conventional completions, reducing field development costs by allowing reserves to be targeted with fewer wells Rudies formation in Belayim Land field is a bottom water-drive reservoir with a strong supporting aquifer. it is characterized by its great isotropy and heterogeneity where based on the analysis of SCAL data, it was found that the vertical permeability is nearly equal to horizontal permeability raising the problem of water coning(cresting), earlier water breakthrough situation and masking the oil production by water due to the great difference in mobility Based on calculation of the critical coning production rates and water control plots it was concluded that the horizontal wells drilled in Rudies formation which are produced with high production rates suffered from extreme water coning problems that raised the necessity for water shutoff procedure to be considered Field cases presented on this paper explain applications of internal casing packer and blank tubing as a tail pipe in accompanied with downgrading the production rates from horizontal wells for the purpose of zonal water control in the uppermost section of open hole and slotted liner completed horizontal wells in Petrobel Included in this paper are two different field cases for uncemented water shutoff in horizontal wells that succeeded in decreasing the water cut in the wells from the range of (90-95 %) to the range of (10-30%) implementing a huge increase in the gained net oil towards achieving the maximum recovery. Technical data including well configuration, production performance and casing string are included in the paper. Field operations and lesson learned from each application are also presentedinthispaper

Traditionally, several multiphase hydraulic calculations are required to determine the permissible surface-parameter operating envelope in underbalanced drilling (UBD) operations to estimate how bottomhole pressure (BHP) and the desired underbalanced condition can be achieved. Furthermore, the complexity consists of running several combinations of gas- and liquid-injection rates and overlapping these results with operating constraints, including the operating range of equivalent liquid rates for downhole mud motors, minimum annular velocities for effective hole cleaning, desired BHP, and respective surface-equipment limitations, to visualize a comprehensive spectrum of viable surface parameters. This paper explains and illustrates a novel method for obtaining quick and comprehensive operational envelopes for underbalanced drilling operations. The model used for pressure-drop calculations considers the effect of geothermal and string temperatures, detailed drillstring and wellbore geometries (including tool joints), formation fluid influxes at several depth intervals, cutting-slip effects, and surface back pressure. This model also enables the evaluation of the behavior of multiphase drilling fluid using different gas correlations. The system determines bottomhole pressures for several combinations of injection parameters and automatically collects results to generate a permissible operating area (envelope). Measured times to generate the operating envelope graph and a comparison of the results are evaluated for several methods and wellbore hydraulic simulators; a qualitative evaluation and validation against field data is also included. The method outlined in this paper offers an alternative to automatically obtaining a gas- and liquid-injection operating envelope, which results in a time savings of three orders of magnitude, as compared to traditional procedures and computational solutions. One of the limitations of the model is that the operating envelope is for a single wellbore depth and provides a representation of the pressure achieved at a fixed depth. Recommended developments will consist of the ability to visualize BHP values for drilling depths, perhaps through a 3D graph. This paper describes the method used by a multiphase flow simulator to create a graph that aids in determining and visualizing the operational area to achieve a specific BHP, including the hydrostatic and friction-dominant areas of circulation; this development will facilitate the decision-making process while designing the wellbore hydraulic aspects of an underbalanced drilling operation. The benefits of the multiphase flow simulator include a significant time savings to obtain a visual representation of bottomhole conditions and the ability to quickly achieve optimized results by means of a broader sensitivity analysis.

Data collection throughout the exploration stage is of paramount importance, especially for the unconventional projects. Since a vast amount of data is acquired through the well logging, large logging expenditures are usually incurred. In unconventional projects, marginal economics dictate particularly strict budget strategies, including expenditures for logging activities. A significant component of the logging costs is associated with the tool temperature rating. In northern Oman, the bottomhole static temperatures of the tight sandstone gas formation being explored are 175°C [347°F] or higher, which coincides with the upper limit of the conventional logging tools. It has been observed that the tool failure frequency increases dramatically when this limit is approached, leading to repeated logging jobs or regretted (missed) data. The simple way to increase the temperature rating of logging tools to perform at high bottomhole temperatures is to use ceramic electronic boards. However, the cost of this solution is roughly 10 times higher than standard tools. Slightly less costly is acquiring data with logging-while- drilling techniques; this has its own disadvantages, such as logging tool availability and data resolution. Another possible approach is careful assessment of the bottomhole temperature at particular times during logging to enable using conventional tools with lower temperature ratings. The assessment is a challenge itself. Direct measurements are difficult because the temperature gauges on logging tools are affected by heat from the electronic components. It is possible to simulate borehole conditions, but this requires extensive modeling and involves many variables such as cooling from mud circulation; heat transfer among the formation, annulus, and drillpipe; conversion of mechanical energy from drilling to heat; and the addition of hot cuttings to mud. That latter modeling has been performed and verified with the field data in various conditions: vertical and horizontal geometries and different mud types. The study established the achievable bottomhole circulating temperatures at various operations, duration of safe temperature window for less-expensive logging, and the bottomhole temperature profile in various drilling scenarios. This allowed delineating a road map for logging future high-temperature wells in the field.

The Western Desert accounts for approximately two thirds of Egypt's surface area. The region can be divided into a number of large scale structural provinces which developed along lines of weakness in the African basement, in response to lateral movements between Europe and Africa. Seismic evidence has revealed a subsurface comprising a series of low relief horsts and grabens. In places however, the structural history is more complex. The Yusif field located near the Qatara depression, is habituated and, therefore has poor seimic data. Three wells were drilled in the field, Yusif -1X, Yusif-3, and Yusif-4 respectively. The fourth well is planned for the most promising area between the three wells. Formation microimaging was performed in the three wells, and interpretation of the images helped to delineate the sand body propagation and geometry in the field and choose the most promising area for drilling the fourth well. The Lower Abu Roash “G” member usually appears as a fining upward profile from conventional openhole logs. Facies analysis was performed on the “G” member with manual sedimentary dip picking, which revealed the internal structures and directions that can't be observed from conventional logs. Correlation with existing openhole logs showed continuity in the vertical and lateral distribution of the sand body, and queries about the relation between the sand bodies in the three wells arose. The relationship between sand bodies can't be solved by conventional openhole logs correlation. Paleocurrent analysis was performed for the sand bodies in the three wells. The results showed that the main trend of the channel belt propagation is NE. Yusif-3 and Yusif-4 wells were drilled within the channel belt while Yusif-1X location was at the channel margin. Correlation is based on electrofacies, which was extracted from high-resolution formation microimaging in the three wells. It was found that the “G” member top is changed based on high-resolution electrofacies detection, and the fourth well was placed closer to Yusif-3 and Yusif-4 based on the recommendations on the channel activity propagation as identified in the formation microimaging. The sand body thickness in the fourth well was almost double the thickness that was found in the previous three wells.

West Dikirnis field is located in the Nile delta of Egypt. It contains a thin oil rim with a thick gas cap and strong water aquifer. It is considered the second oil discovery in the Nile delta after El Tamad Field (Operated by Petroceltic & El Mansoura Pet Co). The development of this thin oil rim is very challenging due to: 1) complexity of the fluid system (volatile oil, retrograde condensate gas cap gas), 2) complexity of the geology of the field (compartmentalization, fracturing, and rapid lithological variation), 3) high heterogeneity in reservoir properties (permeability ranges from 200 mD to 11 D), and 4) strong water drive. This paper represents a case history of developing WD field. It presents a complete development plan of this thin oil rim and its rich gas cap and how to maximize liquid (oil & condensate and LPG) recovery through different stages by optimizing drilling/completion strategy, reservoir management, and production processing. The production strategy of this field was put into phases. In the first phase, the thin oil rim reservoir was developed through vertical and deviated wells for the purpose of collecting geological and reservoir engineering data required for full field development. In this phase the simulation studies showed positive effects of recycling the produced gas into the reservoir gas cap for the purpose of maintaining the reservoir pressure and decreasing the liquid losses due to the expected retrograde condensation in the gas cap gas. This first phase has shown strong, but variable, aquifer effects on the production wells. It also showed a great deal of lithological variations within very short distances in the field. In the second phase, and to overcome the geological and aquifer heterogeneities, it was decided to develop the field with horizontal wells completed with ICD's (Inflow Control Devices). This type of development helped achieve the following: (i) overcome the geological complexity, and (ii) to keep the well away from the water table, (iii) control the water rise by gas cap gas recycling, and iv) normalize the water moving front towards the well bore by the use of ICD's. The studies have shown that the above strategy increases the oil recovery factor by about 50%. In the third phase an LPG & Refrigeration project was constructed in order to maximize the liquid production from this field. Currently, an EOR project is put in focus for further increasing of the liquid recovery from this field partly through vaporizing the remaining oil.

Tight heterogeneous clastic and carbonate formations present great challenges in terms of reservoir fluid characterisation and downhole fluid sampling during exploration phase. The low mobility imposed by the tight clastic formations usually prohibits conclusive formation testing and sampling using conventional wireline formation testers (WFT) with single probe. The small flow area provided by single probe typically does not allow single phase reservoir fluid withdrawal in such low mobility environment due to the high pressure drawdown. In addition, the optimisation of pressure drawdown is critical to ensure single phase and representative downhole reservoir fluid sampling within the allowed station time. On the other side, the heterogeneous nature of the carbonate pore system imposes a significant mobility range, varying from very tight to good permeability intervals. Pinnacle reef carbonates are often naturally fractured. The natural fracture system may cause fluid losses resulting in drilling and data acquisition challenges. Detailed planning and careful consideration on various testing options available is needed to address this high mobility variation and subsequently to maximise the data acquisition at minimum operation cost, time and risks. This work presents case studies demonstrating a new WFT approach in appraising tight laminated sandstone and carbonate reservoirs in offshore Malaysia fields. An initial attempt with conventional technology did not allow to obtain any conclusive formation pressure measurement, pressure gradients, downhole reservoir fluid identification and sampling. On the other hand, the application of WFT Dual Packer offers limited pressure drawdown range and requires extended station time usually resisted by drillers. Realising the importance of these exploration wells to verify potential reserves from initial geological and petrophysical data, it became crucial to search for an alternative technology to achieve the fluid evaluation objectives in a time-effective manner. This paper presents a new approach and methodology that was implemented and resulted in reliable reservoir rock pressure, mobility, and sampling while improving operational efficiency. As a result, it was possible to successfully evaluate the reservoirs of interest and meet study objectives. This work will also provide a proposed best practice, workflow, and recommendations supported by field data examples.

Field development plan is a set of operations and decisions by which oil reservoirs are identified, evaluated and developed. Making smart reservoir development plan depends on the ability to analyze and integrate the available data. In this work, a conceptual short-term study was performed with the objective of determining the optimum conditions for required application of waterflooding pilot project in Upper Bahariya Formation (Ferdaus field / Egypt) in order to maintain the pressure and increase the oil production rate. The integration between the geological and engineering data identified the reservoir structure of Upper Bahariya formation which includes two isolated formations: Upper Baharia 2 and Upper Baharia 3. The original oil in place of Upper Baharia 2 is about 5 MMSTB, while for Upper Baharia 3 is about 11.9 MMSTB. An efficient monitoring program design, for the waterflooding pilot, including three different injection scenarios with 12 response cases, to investigate the uncertainties of the static model are presented. The results of the pilot study scenarios are very encouraging to implement the waterflooding pilot. Recoverable amount of 2 MMSTB will be achieved upon performing the full scale waterflooding project. Such study is an original conceptual contribution to the knowledge of the integration between geological and reservoir engineering data to design of a comprehensive waterflood program.

Kuwait Oil Company has embarked on an ambitious project of drilling development wells to exploit the Najmah-Sargelu and Middle Marrat reservoirs at depths of 14,000 to 17,000 ft. These Jurassic formations consist of layered shales and limestones, which can be heavily fractured and highly pressured. The wells drilled to these prospects are very challenging because of HPHT conditions, narrow pore/fracture pressure windows, and high levels of H 2 S and CO 2 . During drilling and production high concentrations of H 2 S and CO 2 have been recorded. Given the strategic importance of these gas prospects, a study was undertaken into the metallurgy of materials planned for these production wells. With high levels of toxic gases and HP conditions, the severity of sour service was evaluated to be within the most severe area when referencing NACE standards. Dependent on well bore fluid and onset of any water production, Stress Corrosion Cracking (SCC) and Weight Loss Corrosion could occur leading to material failure and lost production. After this study, the use of CRA materials was recommended in future wells to counter these challenges. The application of CRA for down hole tubular and surface wellhead equipment has gained wide acceptance in sour fluid service in recent years especially in HPHT wells. CRA usage has increased to; eliminate intensive corrosion inhibition programs, reduce maintenance costs and enhance safety. Considering the key parameters influencing corrosion properties of CRA (temperature, partial pressure of H 2 S and CO 2 , pH environment, chloride concentrations), it was decided to specify the use of 28 Cr CRA material for these Jurassic gas wells. This paper will discuss the initial study of the material metallurgy, the well design, the specification of tubulars and wellhead, special procedures necessary to run these exotic materials plus details of actual operations in the first wells.

This paper describes the application of a new numerical model to simulate any work over plans in order to assess the work over efficiency and the well productivity enhancement, prior to operations commencement. A case study is discussed, where an operator in Egypt had a plan to improve the productivity of an oil well producing from a multi-layer reservoir, where a low productivity layer had been previously identified and characterized by multiple techniques. It was critical for the operator to enhance the productivity across this layer and to identify the appropriate remedial action (water shut off, re-perforate, or stimulation) that could impact the whole field production performance. The operator had decided to re-perforate and add new perforations to the low productivity layer. The numerical simulation model was hence applied to assess work over techniques and to determine the most suitable remedial action for implementation. The simulation result of reperforation and adding new perforations showed water cut drop by 6% with an increase in oil rate by 538 b/d and in water rate by 348 b/d compared to the initial profile identified by production logging. The result of the numerical simulation model suggests that the low productivity layer should be considered as a candidate for stimulation (fracturing/acidizing). When the operator attempted to re-perforate the low productivity layer, the production performance after the re-perforation did not show a major improvement, as the water cut decreased by 6% only with a small gain in oil rate, which is in agreement with the simulation model outcome. The operator understood the reason for the field wide low productivity from this layer and hence obtained a key to unlocking the reserves contained in this layer across the whole field in future field development plans.

A practical optimization approach has been coupled with a commercial reservoir simulator to evaluate the optimal number and locations of infill wells in a conceptual sector of the Main Pay in South Rumaila Oil Field in Iraq. This field, of 58-years of production, has 40 producing wells. There is also an edge water drive from the infinite active aquifer at the east and west flanks. The water drive from the west flank is more than 20 times the drive from the east flank. Therefore, twenty injection wells have been drilled located at the east flank to maintain and balance the reservoir pressure. After achieving the reliable history matching and running the simulator for a future period until 31 December 2020, the optimization approach has been implemented via spreadsheet considering the aspects of Net Present Value as objective function. The Net Present Value (NPV) is a function of economic variables representing costs and revenues. The revenue is directly proportional to the cumulative oil production that has been predicted by the reservoir model for the entire field. The costs include capital (CAPEX) and operational (OPEX) expenditures. There are ten assigned location of wells taken as a premise to be production wells. These 10 locations have been ranked according to the highest value of permeability and oil saturation spatial distribution in the reservoir in order to be evaluated considering achieving the highest NPV. The optimal number of infill wells was three, six, and ten when the NPV is calculated by the end of 2015, 2017, and 2022, respectively and all the wells at the three cases located at the crest of the reservoir. These optimal wells don't have the maximum cumulative oil production; however, they have the maximum Net Present Value especially at the first two prediction cases.

An oil well with two perforated zones had an initial production rate of ~2,400 BOPD with water traces. Within 3 months, production decreased to ~1,000 BOPD and water cut increased to >25%. It was critical to identify the cause of decreasing productivity and increasing water cut to plan for remedial action. The reservoir was evaluated by integrating several answers obtained from reservoir saturation characterization through use of pulsed neutron capture and water-flow log data, as well as from conventional and advanced production logging. Production logging showed that water was sourced from the lower perforated interval, while only a small proportion of the flow came from the upper reservoir layer. Pulsed neutron logging confirmed a high amount of depletion in the zone below the lower perforation, with oil remaining in the upper part of the lower perforated zone and in the upper perforated zone. Bypassed oil was also found below the water-producing zone, confined between the oil/water contact and a thin shale break. This shale break is a major permeability barrier and allows lateral water movement through the high-permeability lower zone. A multilayer test carried out with production logging tools showed that the productivity index of the upper zone was only one-tenth that in the lower zone, due to either intrinsically low permeability or high skin factor. The multilayer testing also showed that of the two comingled layers, the upper layer had approximately one hundredth the permeability of the lower layer. Reperforation of the upper zone resulted in only minor improvement in well production, thus confirming that the low productivity was not caused by high skin factor, but was due to low permeability. From the testing, it is clear that to produce the oil from the upper zone, it will be necessary to produce the two zones separately, with different drawdown. Since similar conclusions were obtained in other wells in the field, these results provide a fieldwide strategy for improving field productivity.

Although heavy oil producers in Block 6, Sudan have been difficult to exploit with gas lift because crude oil has 19 °API, the reservoir pressure was low, and surface dead oil viscosity ranged from 30,000 to 40,000 cp. New advances have recently been made to increase oil production. These innovative practices include: (1) Injected condensate gas into the reservoir prior to gas lift, and soaked for a time (e.g.one day) sufficient for condensate-gas to dilute the heavy oil's API gravity, reduce viscosity, and pressurized the zone near the wellbore. (2) Large tubing string was extended to near the bottom of perforations, gas lift valves were not utilized to ensure that a continuous volume of high-pressure condensate gas was injected into the annulus, could blend with heavy oil at the bottom hole and avoided multi-point injection caused by possible sanding. (3) Sand trap was installed to capture the produced sand. (4) Injection pressure and injection gas rate were optimized to produce more condensate from the gas condensate reservoir for dilution of heavy oil at the wellbore. Field data show that these new techniques have gained excellent results, with oil gain of 6-fold compared to average oil rate by PCP.

Issran field is located 200 km east of Cairo-Egypt, producing from fractured dolomite reservoir 8-12 API oil gravity. The reservoir depth ranges from 1000-2000 ft, with BHP 300-500 psi and BHT of 120-200 F. The heavy oil viscosity is 4000 cp at standard conditions and the reservoir rock is oil wet with high H2S content. The high viscosity and low mobility of the Issran field heavy oil in contrast with the strong mobility and low viscosity of the formation water had extended the problem to a severe decline in hydro carbon production. In an attempt to enhance the production, Steam injection had been deployed in the field to reduce the oil viscosity and hence enhance the mobility of the extra heavy oil. Enhancement in production has dramatically increased after implementing a new technique combining the Steam Injection with the Matrix Stimulation Engineering Utilizing the Fiber Optics Telemetry Enabled Coiled Tubing. As the first time in the East Africa and East Mediterranean countries, the new technology deployed (Fiber Optics Telemetry Enabled Coiled Tubing) has provided a new dimension to the heavy oil thermal recovery by supplying a full Distributed Temperature Survey (DTS). Real time interpretation of the DTS data enabled the real time decision making during the Matrix stimulation treatment based on the actual downhole parameters. It also provided valuable data regarding mapping of the downhole steam injection utilizing coiled Tubing. This paper assesses the effect of using the new technology in Coiled Tubing services utilizing the DTS Measurements during Matrix Stimulation Treatment in different wells. It analyses the Successful production enhancement that provided a new dimension to the extra heavy oil enhanced recovery efficiency. It also quantifies the economical added value resulting from the usage of DTS data in respect to conventional matrix stimulation with conventional Coiled Tubing.

DCA (Decline curve analysis) is one of the most powerful tools used in defining well/reservoir worth. DCA aims at estimating reservoir production performance at any time (of production) post plateau period providing realistic and well documented production data. DCA helps in developing production-rate/reservoir-pressure distributions to determine well/reservoir productivity scheme. Forecasting well/reservoir production rate, estimating remaining reserves, monitoring GOR & WC behaviors, deciding on reservoir pressure support and determining economic limits are among the many befits of DCA as well. In this study the AOR (Actual Oil Rate) method has been implemented utilizing the DCA, FASTRTA™ and Ecrin packages to calculate remaining and recoverable reserves in particular. The remaining reserves depend on the production data that are selected to represent the actual well/reservoir behavior. This technique allows eliminating misrepresenting production data due to human error, imposed production rates caused by internal company policy or external factors (politics, natural disasters, etc.) during production life of the field. A case study has been used as a pilot for the proposed method. Analyses have been performed on both well and whole reservoir scale. The outcome yielded more realistic results using AOR and generated very useful development recommendations. The proposed AOR-DCA adopted technique can assist in accurate decisive parameters estimate of both mature and under-development oil reservoirs worldwide.

The oil and gas industry has a need for reliable monitoring of changes in wall thickness both topside and subsea. It is important to detect and monitor the effect of corrosion and erosion as this may reduce the life-cycle cost and increase the lifetime of industrial infrastructure, ships, aircrafts, ground vehicles, pipelines, oil installations, etc. Even topside the conditions of operation can be extremely hostile, facing problems like surface roughness, fluid loading issues, temperature variations, and a host of other factors that make development of a robust wall thickness assessment tool a challenging task. Deploying a monitoring system subsea makes the application even more demanding when you have to take into account factors like high pressure and limited access. Over the last years ClampOn have offered a topside corrosion-erosion monitor (CEM) for monitoring changes in the wall thickness of such infrastructure. Major advantages of this technology have been its non-invasiveness, high repeatability, high coverage and the lack of any transducer movement, also making it an excellent candidate for subsea use. The measurement principle is based on dispersion of ultrasonic guided wave modes, and by using electromagnetism these waves can be transmitted through the pipe wall without the sensor being in direct contact with the metallic surface. It is installed on the outer pipe wall to produce real-time wall thickness information – not as a spot measurement, but as a unique average path-wall thickness. With several successful installations topside, the technology has now also been made available for subsea installation.