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IPTC 2014: International Petroleum Technology Conference
- Conference date: 19 Jan 2014 - 22 Jan 2014
- Location: Doha, Qatar
- Published: 19 January 2014
101 - 200 of 354 results
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Reduction of the Carbon Footprint in Ammonia Production through Petrochemical Plant Integration in Qatar
Authors S. Daghash and F. BenyahiaThe gas industry in Qatar is experiencing a massive growth and its energy consumption leads to significant carbon emissions specifically Carbon Dioxide (CO2). All plant operators have been required to report carbon emissions to local authorities according to international standards. However, it is not clear how carbon will be managed in the future. In this work, a potentially attractive solution for carbon management will be put forward. This work involves a case study on Ammonia production facility and the carbon footprint of the Ammonia process. The sources of CO2 investigated were from the Ammonia process itself and its main support utilities (combustion in gas turbines, steam boilers and natural gas reformers). Refering to previous work done (on Ammonia process simulation using industry standard HYSYS and process calculation using a spreadsheet), an attempt was made to recover CO2 from the process to be utilize in Urea and Methanol manufacturing. This approach was based on the concept of plant integration where Ethylene, Ammonia, Urea, and Methanol production facilities would have a certain degree of mass integration. The work highlighted the importance of the Hydrogen balance from the Ethylene facility and the extent of CO2 recovery and capture from the Ammonia facility. The results indicated that it is possible to target around 45% of CO2 produced in Ammonia manufacturing and utilize it to produce high value products such as Urea and Methanol. It was found that when excess Hydrogen is utilizaed with part of CO2 produced from Ammonia manufacturing facility, excess Methanol that is equivalent to a half a train capacity can be produced (~1424 MTPD*). In addition to that it was found that utilizing another part of CO2 with Ammonia product - that is usually gets exported – almost one train of Urea can be produced (~3728 MTPD). The concept of plant integration was found very powerful and relevant in the context of carbon management since it is known that captured CO2 in Qatar and gulf area may not be stored underground in large quantities because the geology is mainly carbonate reservoirs. The work also indicated the need to purify both CO2 and hydrogen to qualities compatible with the applications indicated. A network of hydrogen and CO2 pipelines was also highlighted in the plant integration study. This plant integration of important petrochemical processes has shown that it is possible to reduce significantly carbon emission in Ammonia manufacturing.
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Effective Management of Cathodically Protected Plant Facilities in a Complex Gas Processing Plant
Authors J. Shanmugam and Z. HazosOil and Gas industries always have complex buried piping networks inside their plant facilities. Buried piping and other structures usually get multiplied due to frequent expansion of the plant facilities over years. Most of the buried piping is protected by dedicated impressed current Cathodic Protection (CP) systems installed during each expansion project. Furthermore, most of the buried piping is usually tied in with existing piping during the expansion projects, mostly without electrical isolation joints. No attempt is usually made by the CP designers to utilise the existing CP systems. Even though the buried piping is protected by distributed shallow groundbed anode systems, they are influenced by other CP systems and existing piping network due to shallow water table and associated low resistivity soil. Adding to the complexity of the piping network and the multiple CP systems, installation and commissioning of CP systems are usually handled by different personnel who usually are not fully aware of the importance of the CP systems, its installation, and proper commissioning. Experience shows that CP systems are not given its due importance during the project implementation, sometimes with improper design, installation and commissioning data. The scope of this paper is to brief the methodology used to ensure reliable operation of the cathodic protection system in order to protect the buried, immersed structures such as piping, tank bottoms, vessels and concrete structures exposed to marine atmosphere from external corrosion.
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An Integrated Method of Subsurface Illumination Analysis for Shallow Gas Anomaly Data
Authors A. Abdul Latiff, D.P. Ghosh and Z. Tuan HarithIn near surface anomaly region such as shallow gas accumulation and salt diapir, the acquired seismic data often suffer from poor quality image (shadow zones) due to low illumination coverage at subsurface reflector. Degraded signal information within these zones often been associated with multiple scattering of ray propagation or absorption of wave energy during seismic data acquisition stage. The distorted image underneath gas zones was caused by three factors: (i) properties of near surface anomaly; (ii) location of target reflector (both lateral and vertical position); and (iii) source-receiver configuration at surface level. Previously, the quality of subsurface data was determined by extrapolating source and receiver wave field, thus creating a pair of focal beams which can be used for evaluation of acquisition design. The highly successful focal beam method demonstrate the relationship between subsurface illumination and acquisition configuration by analyzing resolution and amplitude versus ray parameter (AVP) functions of target locations for a given geometry set-up. Another way to analyze subsurface illumination is through ray tracing method, where rays were propagated from source to target depth and reflected back towards the surface level. During reflection process, illumination will be measured by counting the number of rays hit the target reflector while taking into account incidence ray angle and travel-time measurement. Although both analyses will estimate the amplitude coverage of target reflector, confidence level of illumination quality is still lacking. With this view in mind, we are proposing an integrated method of illumination analysis known as Illummination Factor which based on focal beam and ray tracing methods for better subsurface illumination guidance. The Illumination Factor is formulated based on seismic attributes information from two forward modelling methods; amplitude distribution in spatial domain (focal beam analysis) and number of rays hit at target subsurface (ray interpolation). This new illumination indicator will be used for evaluating a near surface anomaly velocity model, in terms of its confidence level. Evaluation of Illumination Factor in this seismically complex region will set a basis for improving seismic acquisition design, enhance seismic data through better illumination while provide an insight for reservoir characterization.
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The Applications of Laser Technology in Downhole Operations - A Review
By A.W. AdenijiDownhole operations in the petroleum industry include drilling and completing the well for production. Experiments conducted on different types of lasers have shown the potential of the cutting - edge technology being applied in downhole operations. One of the tests was conducted on MIRACL (Mid Infrared Advanced Chemical Laser) to determine its feasibility for drilling and perforating petroleum wells and another was on COIL (Chemical Oxygen-Iodine Laser) to determine the least specific energy (SE) needed to destroy varying rock types. This paper presents the applications of laser technology in downhole operations such as drilling, perforation, stimulation, vaporizing stuck pipes, tracer detection, treatment of asphaltene deposition and cutting of subsurface equipment such as casings, tubing strings etc. Its benefits are presented in terms of effects on Rate of Penetration (ROP), operational downtime, formation damage, clay treatments, flow enhancement and overall well deliverability. Laser technology has been utilized successfully in the medical industry, manufacturing industry, nuclear industry etc. Therefore, its applications in downhole operations are major strides in the petroleum industry and a means of optimizing downhole operational practices. It has been reported that integrating laser technology with conventional drilling technology will immensely improve drilling efficiency but this has not been so far applied in the field. Conclusions derived from a two year project funded by The Gas Research Institute (now Gas Technology Institute) in 1997 on "Adapting Star Wars High-Powered Lasers to Drilling Natural Gas Wells," are that lasers can cut rock of all lithologies; shear power shares importance in cutting rock with such parameters as wavelength, purge gas pressure and hole size; and historical and widely accepted theoretical calculations of the laser power needed to spall (break), melt and vaporize rock are significantly higher than experimental values. Just like any new technology, laser technology has its challenges and they are highlighted accordingly.
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A Novel Approach for Production Stimulation through Chemical Applications in A Saudi Arabian Offshore field
Authors A.A. Balto and H.B. QahtaniThis paper includes a discussion of a progressive approach and recent practices to stimulate wells in one of Saudi offshore fields. A chemical treatment pilot aimed for production enhancement was recently conducted and proven successful in an offshore environment while recognizing merits associated, including fluid placement optimization in terms of logistics and time beside treatment effectiveness. Implementation of such practices has increased chemical treatment success rate, enhanced well production performance, reduced cost and improved operational HSE practices. The recent chemical treatment applications and practices were the outcome of five years of dedicated search and collaboration with service companies to find the most effective chemical recipes and their deployment method. The campaign was initially piloted in three different wells completed with inflow control devices wrapped with premium screens, using three different chemical applications while utilizing a distributed temperature sensing (DTS) technology for the first time in an offshore field to evaluate treatment effictiveness. Initially, three wells were completed in high permeable and contrasted sandstone layers. Those wells are completed with sandstone screen completions coupled with inflow control devices to control sand production while providing a degree of production management across the producing lateral. The completion practice prior to the pilot did not allow an efficient cleanup due to HSE and operational considerations. Extensive technical, operational and economical evaluations were conducted to ascertain the best chemical recipe, fluid placement technique, equipment and applications used to ensure the proper treatment exposure to the damaged zone for better production output results. Horizontal completion practices have changed; hence new challenges have arisen to consider for instance the best contemporary placement technique used for treating fluids in different type of horizontal completions. Long horizontal sandstone producing laterals in the past, which used to be completed as cased and perforated are being completed as open hole laterals with inflow control devices coupled with screens where the fluid placement technique must vary to account for best and uniform treatment coverage. This paper will include the pilot results and recognized merits. Offshore production engineering insights will be also shared in this paper.
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Solving The Conflicting Dips Problem In Complex Media By Considering All Possible Dips In CRS Method
Authors A. Shahbazi, D. Ghosh, M. Soleimani and J. MannIn the existence of conflicting dips, where the seismic events are bent, faulted, or pulled up by the salt dome or anticlines or even intersect another structural event, some parts of the events may not be imaged well in stacked section and may produce uncertainty in the final migrated section for interpretation. A modified version of the CRS stack, the common diffraction surface (CDS) stack, is a method that could solve the problem of conflicting dips that may happen frequently in complex and semi-complex structures. This strategy has some advantages that improve the continuity of reflection events as well as diffractions in the presence of conflicting dip situations. To investigate whether it could solve the seismic imaging problem in such media, we processed the Sigsbee 2A synthetic data and a real seismic data set with the new method. Finally, the stacked result of Sigsbee 2A and the results of the poststack depth migration of the real data also proved that the continuity of the events is fully preserved and there are no gaps in the diffraction events, even where they intersect other events. This method could resolve some of the ambiguities of imaging in complex structures.
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NMR Measurements for Pore Size Mapping at Fine Scale
Authors A. Valori, F. Ali, A. AlZoukani and R. TaherianAs fluids move through a rock their flow path is controlled by the capillary forces from the local pore size distribution. The pore structure causes the fluid not to follow a simple path which is a familiar challenge in reservoir production and recovery. In this paper we examine this effect at a small, more manageable scale of a core plug in laboratory. Fully water saturated plugs were centrifuged in air using small capillary pressure steps. At each step the T2 distribution of the core was measured. The capillary pressure steps were incremented at one psi steps for careful mapping of the evolution of fluid distribution. In this experiment the water was replaced by air which has no NMR signal, thus the results clearly showed gradual removal of free water from the larger pores with no reduction of bound water signal. Comparing T2 distributions from different capillary pressure steps, we were able to pinpoint the pores contributing to fluid displacement at each pressure. These results, for the first time, reveal more detailed pore information that is apparent from normal T2 distribution alone. The new approach enables deeper understanding of rock pore structure and how the fluid distribution is influenced by the pore sizes involved in conducting the fluid. These results, once up-scaled to reservoir level, will help optimize and improve oil recovery. The technical contribution of this paper includes pore size study at a finer scale by NMR than previously reported.
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Geared Centrifugal Pump (GCP) Technology Implementation in Petroleum Development Oman, as a Potential Alternative Artificial Lift Method – Oil Wells
Authors A.S. Al-Bimani, A.I. AbdulElraouf, A. Al-Salmi, Z. Al-Hinai, W.B. Morrow and R. Al-MasfryThe Company’s 5-Year Business Plan shows that well operating cost (OPEX) is increasing, especially for mature fields. It is anticipated that some mature fields will not be economic to operate if these cost continue to rise. The lift and well servicing costs are key components of the well OPEX budget. Given that 90% of the company’s well stock is completed with artificial lift system, new lift technologies with potential savings are needed. The operating companies have always been looking for alternative lift method to lift high volume wells at lower cost. The Geared Centrifugal Pump (GCP) is a new high volume artificial lift system that combines the rod string drive of a progressive cavity pump with a multi-stage centrifugal pump of an ESP, via a down-hole speed increasing transmission. It is anticipated that this new system will reduce costs associated with well intervention as failures related to the drive string can be executed by smaller well service units. In addition, electrical and drivehead mechanical failures can be rectified at surface at less cost. Moreover, the GCP pump is cost effective equipment as it eliminates the expensive motor, cable and surface controller. In this notion the GCP pump will address both the lift and servicing cost challenges when compared to other lift systems. PDO expects to complete all six pilot GCP installations in two of the north Oman fields before performance of the GCP system compared to the widely used ESPs in the same field. At the end of end-2nd qtr. 2013. The objectives of this pilot trial are to test the efficiency, reliability and operational the approx. one-year trial period, the technical and commercial values will be quantified and thus confirm the viability of deploying the lift system further. This paper will discuss trial objectives, deployment experience, real time monitoring, troubleshooting & optimization. The paper will also highlight the technology challenges; lessons learned and improvements including future deployment plans for PDO.
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An Adapted Uncertainty Management Methodology and Tool for Fast-Track Approaches: Light-Up
Authors S. Ahn, P. Schirmer and E. TawileLight-Up (for Light Uncertainty Process) is part of TOTAL’s in-house tools for uncertainty management. Light-Up provides (1) the assessment of the probabilized HIIP distribution and (2) the methodology and tool to build “tailor-made” models that feed fluid flow simulation for reserves evaluation with or without dynamic uncertainties. Because the uncertainty workflow of Light-Up is pragmatic and fast, Light-Up has been used for several years on a large panel of TOTAL operational cases. The uncertainty workflow which includes Light-Up, composed of 4 main steps, constitutes an integrated workflow.
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Improving Collision Avoidance and Target Accuracy in an Offshore Brownfield Redevelopment Combining Gyros and In-Field Referencing
Authors H. Costeno, M. Djohor, M. Raziyev, H. Sessarego, B. Subroto, A. Ismail and S. Lyn LeeIn 2012, a redevelopment infill drilling campaign took place in a brown field, offshore Malaysia. Accurate wellbore positioning was critical to place a well within a path that navigates 2200 ft through an antithetic faults panel, separated approximately 900 ft, and with a 120 ft general throw; and to intersect the five target reservoirs of the well. The complex well path also faced the challenges of infill drilling in a brown field, such as collision avoidance in a crowded field, the location of the target reservoirs relative to the available drilling slots; as well as trajectory restrictions due to completions design. This paper presents the well design solutions that include a rigorous anti-collision analysis and a comprehensive survey programme. The survey programme consists of gyro while drilling (GWD) on the upper section of the well until the path is clear of magnetic interference from neighboring wells and the application of in-field referencing (IFR) correction for conventional measurement while drilling (MWD) magnetic survey based on accelerometers and magnetometers. IFR improves survey accuracy with a multi-station analysis that corrects the survey error with the localised crustal effects in the magnetic field of the earth. It was used for well positioning in between faults and for target intersection. It enabled drilling the well with higher confidence while intersecting the target reservoirs. A reduction of 60% on survey uncertainty was observed. The more accurate wellbore survey also optimises collision analysis for future well plans and it gives more reliable control points to update the subsurface static model. The benefits were obtained without compromising the drilling performance given that no extra operational time is required for the survey correction.
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New Methods for Quantitative Reservoir Quality Prediction in Sandstones
Authors A. Consonni, A. Ortenzi and C. GeloniThe efficiency of a sandstone reservoir is a function of the initial depositional parameters (grain-size, sorting and composition) and of the post-depositional evolution during burial. The depositional parameters are closely linked to the sedimentary environment and the post-depositional evolution depends on the paleo-dynamic geological setting that conditions both the burial rates and the temperature history. The reservoir quality of sandstone was appraised in the past mostly in a qualitative way either by using close-by cored wells information or by taking into account the log porosity from adjacent wells. In the recent years more quantitative approaches to predictions were developed. The reservoir quality is currently appraised in Eni E&P with two methodologies. The first is proprietary and is based on the Reservoir Efficiency Index© (e-rei), a quantitative indicator of the quality of a clastic reservoir calculated from thin sections on the base of the quantitative petrographic data. A dedicated geostatistical tool (Softkrig) was developed in order to map the e-e-rei values on the base of TWT, depth or temperature driver maps.. The second methodology is based on the use of a reservoir quality modelling software (Touchstone™), developed in the frame of an Industrial Consortium and able to predict the mechanical compaction, the quartz cement precipitation and the illite formation and thus to model porosity and permeability. The methodologies are complementary and have been applied on Paleozoic African reservoirs. The main factor, reducing reservoir quality, was identified in the cementation by quartz, while the preserving mechanism, increasing reservoir quality, was recognized in the presence of early diagenetic clay coatings. The case-study shows the pros and cons of applying the two methodologies. In particular the e-e-rei mapping is recommended for the play fairway analysis of reservoir quality, while Touchstone is more suitable for the sensitivity analysis and for the determination of the porosity/permeability values on a given prospect. The two methodologies are limited one by the fact that is deterministic, the other by its ability to model only some of the diagenetic events that take place during burial. In order to overcome these problems, transport-reaction models may be used. A first attempt to apply these models, already used in carbonate diagenesis and reservoir quality prediction, to sandstones showed that there are way forward in applying this methodology.
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Successful Implementation of Real Time Downhole Pressure Temperature Monitoring using Fiber Optic Technology in Deep HT-HP Well in North Kuwait
Authors M. Rezaul Kabir, A. Ali, S.P. Pradhan, Q. Dashti, A.K. Al-Jasmi and R. AbidThe scope of the pilot project was to test fiber optic sensor technology in deep High Temperature (HT-HP) reservoirs and evaluate the best available sensors in the market for real time monitoring of down-hole pressure and temperature (P-T) in such an adverse environment. The task team had selected the optical P-T sensors conveyed on fiber optic cable from a qualified vendor after a thorough evaluation, considering the harsh environment of these reservoirs. After selecting the vendor, the fiber optic system was custom designed and installed down-hole in a selected deep HT-HP well in the Raudhatain field of North Kuwait. The system was installed and commissioned in mid February 2011 and has been successfully working to date, providing real-time pressure and temperature data from the reservoir section. In this project the P-T signals captured by the optical down-hole sensors are transmitted through the fiber optic cable to the Reservoir Monitoring System (RMS) unit at the surface that is connected to the SCADA system. The SCADA system sends the data through Wi-Max to the Digital Data Gathering Centre in the Field Development Gas (FDG) office. The sensors are continuously providing reservoir data at a time interval as frequent as 60 data points per minute. The technology provided by the vendor for this pilot is found to be robust and reliable. The pressure and temperature sensors employed in this pilot have shown impressive resolution and dynamic response capabilities. Based on the results it is concluded that the pilot is successful and the system is recommended for future implementation in deep HT-HP wells of North Kuwait fields. The project involved manufacturing, shipping and procuring the material from the Far-East and the USA. It also involved modification of well head to accept fiber optic cable entry into the well bore and use of specially designed low solid content packer fluid. The pilot was considered successfully completed after monitoring for 180 days in the month of August -2011. In Kuwait Oil Company (KOC) this first fiber optic sensor technology pilot was conducted by Research and Technology (R&T) and Field Development Gas (FDG) with the coordination of Deep Drilling and other groups, in a deep HT-HP well with the primary objective to monitor two key reservoir parameters; temperature and pressure. The reservoirs in North Kuwait are complex soil bodies that have a high potential for condensate and gas. The continuous, real time understanding of these reservoirs is vital in order to optimize their exploitation; hence KOC adopted a strategy of deploying fiber optic monitoring systems.
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New Erosion Resistance PDC Bit Coating Eliminates Balling in Water-Based Drilling Fluids in Saudi Arabia
Authors O. Alvarez, F. Mutair, H. Ghannam, U. Hassany, S.M. Siddik and A. SamyThe tendency of PDC (Polycrystalline Diamond Compact) bits to ball in soft shale formations when drilling with WBM is well documented, especially in deep/high-pressure applications. The capacity of shale to absorb water causes the formation to stick to the bit body and cutting structure compromising drilling efficiency. Balling also clogs the nozzles and junk slots reducing hydraulic effectiveness/cooling leading to accelerated cutter wear and premature bit failure. In Saudi Arabia’s fields, a typical well requires approximately 1,600-2,200 ft of a 12-in. vertical borehole or 3,000 ft of a 12-in. directional borehole to be drilled through carbonates, shale and claystone lithologies. The middle part of the section is composed of mainly claystone, which is the most problematic zone. In recent wells, bit balling incidents through the claystone interval was reducing average rate of penetration (ROP) to less than 10 ft/hr, and in certain cases forced to pull out of hole (POOH). PDC bits with various hydraulics configurations and non-stick coatings were tested in an attempt to alleviate balling issues. The thin layer eroded before the bit entered the problematic zone, exposing the rough bit body. An R&D initiative determined mechanical and electrochemical sticking contributes to bit balling. The investigation revealed a coarse bit body increases surface area and adhesive force. When mud flow stops an electrostatic force can cause clay to stick to the bit surface. Based on these findings a new type nickel-phosphorus electroplating process was implemented that creates a thick/durable coating with an extremely strong chemical bond. This paper reviews the investigation process and findings of three case studies in the Saudi Arabian fields. The new anti balling coating was applied to a seven bladed PDC design and run on a powered point-the-bit rotary steerable system. The bottom-hole assembly (BHA) drilled the entire section achieving a field ROP record. Drill bits with the new anti-balling coating were also tested in vertical wells in different gas fields setting new bit performance benchmarks.
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Innovative Coastal Research in Qatar: Improving Geological and Reservoir Modeling
Authors C.J. Strohmenger and J. JamesonMaximizing recovery in oil and gas fields relies on geological models that realistically portray the spatial complexity, composition, and properties of reservoir units. Present day arid climate coastal systems, like the coastline of Qatar provide analogues for depositional and diagenetic processes that control reservoir quality in ancient reservoirs. Many major reservoirs in Qatar and the Middle East formed under conditions that are remarkably similar to those shaping the Qatari coastlines of today. Major controls on coastal sedimentation patterns are: 1) coastline orientation, 2) wind, wave and tidal energy, 3) climate, 4) relative sea level, 5) depositional relief, and 6) sediment sources. Strong NW prevailing winds (Shamal winds) drive shallow marine circulation patterns, creating four very distinct depositional profiles: windward, leeward, oblique, and protected. Windward coastlines are marked by reef development and intertidal sheet and beach sands. The leeward coast profile is dominated by an eolian sediment supply, as sand dunes are blown into the sea. Along windward and oblique coastlines, shoreface hardgrounds stabilize circulation patterns, creating mud-prone areas of stromatolites and mangroves. Protected coastlines are characterized by finer-grained peneroplid sands and low-relief beaches. Grain size, composition, and dimensions of coastal sands vary due to wave energy. Coastal deposits are equally affected by high-frequency oscillations in sea level. Approximately 6,000 years ago, sea level was about 2 to 4 meters higher than it is currently and the Qatari coastline was up to 10km inland. Most coastal deposits and sabkhas are relicts of this ancient highstand in sea level. Punctuated sea-level drops to present day level have led to the formation of seaward-stepping beach spit systems. Sedimentation patterns and their diagenetic overprint were studied in detail at the coastal sabkha of Mesaieed, which represents an oblique coastal system relatively to the predominant wind direction. Detailed field mapping, radiocarbon age dating analyses, and the integration of geotechnical borehole data, as well as data from numerous shallow pits allowed reconstructing the thickness of the Holocene, the dating and spatial reconstruction of the progradational pattern of the beach spits relative to the varying sea level, and the mapping of the amount and distribution of porosity destroying gypsum. The observed spatial complexity and heterogeneity of modern coastal systems are important aspects to be considered for conditioning three-dimensional geological models. Modern depositional systems along the Qatar coastline, like the one studied at the Mesaieed sabkha, are particularly useful as analogs for conditioning subsurface data sets in geologic (static) and reservoir (dynamic) models.
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Mechanism and Application of Improving Heavy Oil Recovery Greatly by Solvent and Foam Assisted Steam Flooding
More LessThe annual production reached 47.5 million tons in 2012 in Shengli oilfield , almost 96% of which was produced by CSS with low recovery factor of only 18.8%. Steam flooding as the main EOR technique isn’t available for the heavy oil in Shengli oilfield because of the following challenges : (1) the deeply buried depth of reservoirs (more than 1300m) results in low steam quality at bottom hole. (2) high formation pressure makes steam zone narrower and hot water and condensation zone wider.(3) the severe heterogeneity of reservoir causes steam channeling. To improve greatly recovery factor after CSS, a solvent and foam assisted steam flooding (SFASF) pilot was carried out in Gudao Block 2 heavy oil reservoir. The oil production rate of small well spacing pilot increased from 20t/d to a peak of 101t/d, water cut decreased from 89% to 74.6%, and the recovery factor will be raised by 21.8% and up to 57.7% during SFASF. The mechanism of SFASF was investigated. In order to reduce the steam channeling and improve steam uniform driving, N2 and foam agent were injected periodically during steam flooding.A new foam agent was developed, of which the resistance factor can always keep more than 20 under residual oil saturation at 300℃. In order to improve displacement efficiency at hot water and condensation zone, A new anionic solvent was developed and injected during steam flooding so as to decrease oil-water interfacial tension and residual oil saturation. The solvent can make IFT up to 10-3mN/m at 300℃. Moreover, optimum concentration of foam agent and solvent of SFASF is about 0.5% and 0.3% respectively and steam flooding is continuous with one month chemical system plug after three month interval. In order to get better effects high steam quality boiler by superheat, equal dryness distributing and high efficiency wellbore insulation technology were developed. Combining heat with chemical is a trend to improve greatly heavy oil reservoirs recovery factor and the SFASF technique is available for more than 0.174 trillion tons oil reserve in Shengli oilfield.
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Dynamic Reservoir Uncertainty Evaluation for Production Delivery Assurance
Authors M.A. Baslaib, A. BenSadok, H. Arii, M. Espinassous, G. Bourdarot and M. AttiaA new production development scheme was proposed for one of the major offshore fields in the Gulf. To assist building assurance of the delivery of this scheme, subsurface uncertainty evaluation was initiated; firstly based on an in-house approach and later through the use of commercial softwares. The proposed study is primarily focused on dynamic reservoir uncertainties. The objective of this study is to evaluate the impact of the reservoir uncertainties on plateau duration period in the prediction phase. The workflow, based on experimental design and response surface, advantages and outcomes of this study are presented and its limitations discussed. This study was completed over a short period of time, thanks to an optimization of the CPU resources. This was a key advantage obtained while carrying large models with long history exceeding 50 years. The study resulted in successfully delivering probabilistic profiles (P90, P50, P10) in order to assure the production delivery of the proposed development scheme and enables to develop risk mitigation plans. A ranking of the most influential uncertainty parameters with quantification of their interactions is obtained. Consideration is also given to the history match quality, which results in reducing the parameters distributions and highlights the value of the data acquisition.
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Concentric Coiled Tubing Technology Revolutionizes Logging Sub-Hydrostatic, Single-Completion Wells
Authors M. Ababou, A. Shote and T. SturgonSingle-completion, sub-hydrostatic wells were a challenge for production logging runs because two strings of tubing and dual wellhead would be required, necessitating workover rig operations. However, for smaller cased holes such as 7- or 4 ½-in. casings, running a dual completion string is typically too complex or impossible. When operators had to determine water-entry points in fields with high water cuts, well intervention costs could become prohibitive to contemplate. Hence, logging sub-hydrostatic wells to determine water entry points was restricted to a limited number of wells of a particular construction. These wells had to be dual-completion wells or 9 5/8-in. cased wells, able to accommodate dual-string completions. One string would be used for running the logging tool via coiled tubing or wireline, and the other would be used for artificial lift and produce the well while logging. Instead, a conventional concentric coiled tubing (CCT) string can be transformed into a specialty CCT by adding an encapsulated single-conductor wire inside. The string can then be run with a modified vacuum bottomhole assembly and a logging tool to achieve production analysis and logging simultaneously. Combining these two proven technologies into one solution is an economical way to produce the wells via the CCT and its vacuum BHA while logging the well in one run. It has economic benefits to operators by eliminating the high cost associated with installing dual completions and dual wellheads. It also enables logging in 7- and 4 ½-in. cased holes that were not accessible for production logging using prior technologies. This paper will describe the revolutionary technology and case histories along with lessons learned. It will also describe in particular the applications of the technology for high-producing water wells.
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Qatargas Process Safety Program
More LessThe Qatargas Process safety Program is one of the business initiatives within Qatargas to achieve the Qatargas Vision 2015. It is a basic, standardized, operational work process that ensures operation within well-‐defined, well-‐ understood limits. Operation within these limits is continuously achieved through a defined and well-‐ followed set of operational and organizational Behaviors & Procedures at all levels.
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Flow Modeling and Comparative Analysis for a New Generation of Wireline Formation Tester Modules
Authors M. Kristensen, C. Ayan, Y. Chang, R. Lee, A. Gisolf, J. Leonard, P.-Y. Corre and H. DumontWireline formation testing (WFT) is an integral part of reservoir evaluation strategy in both exploration and production settings worldwide. Application examples include fluid gradient determination, downhole sampling, fluid scanning in transition zones, as well as interval pressure transient tests (IPTTs). Until recently, however, formation testing was still challenging and prone to failure when testing in low-mobility, unconsolidated, or heavy-oil-bearing formations, especially with single-probe type tools. A new-generation WFT module with a 3D radial probe expands the operating envelope. By using multiple fluid drains spaced circumferentially around the tool, the new module can sample in tighter formations and sustain higher pressure differentials while providing mechanical support to the borehole wall. We performed a detailed flow modeling-based analysis of the contamination cleanup behavior during fluid sampling with the new module. Using both miscible (sampling oil in oil-based mud) and immiscible (sampling oil in water-based mud) contamination models we studied the cleanup behavior over a wide range of formation properties and operating conditions. Comparison of the cleanup performance of the new module with the performance of conventional single-probe tools demonstrates that the new module is 10 to 20 times faster than the single-probe tools when sampling in tight formations. Finally, we also compared the new module against the sampling performance of dual packers and a focused probe. This work is directly relevant to the planning and fundamental understanding of wireline fluid sampling. The key contributions are miscible and immiscible contamination cleanup models that include the effect of tool storage, a comprehensive analysis of contamination cleanup behavior for the new-generation WFT module with comparisons against conventional single-probe, focused probe, and dual-packer tools, and a characterization of fluid sampling conditions versus the preferred type of sampling tool.
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World's First Tandem 2.125-in. Coiled Tubing Tractor for ESP Open Hole Completions
Authors J. Arukhe, L. Duthie, S. Al-Ghamdi, S. Hanbzazah, H. Almarri, B. Sidle and H. Al-KhameesHydraulic coiled tubing (CT) tractors with 4.7 in. outside diameter have been employed quite effectively for superior accessibility of the CT into extended reach open hole horizontal wells of a giant carbonate field in Saudi Arabia. The use of these tractors has allowed more cost effective chemical placements and well stimulation treatments in these mega reach wells. Relatively large monobore completions (7 in. OD tubing) of water injectors in this field have been necessary for the success of the CT tractor deployment. Challenges remained to conduct similar well interventions into oil producers with hydraulic CT tractors mainly because of smaller completion sizes or restrictions in the completion. Although a smaller OD, 2.125 in. tractor existed, the pulling force of this tractor was insufficient to reliably pull the CT to total depth (TD) in many of these extended reach wells. Subsequently, the wells have not been stimulated to TD which results in reduced production and reservoir optimization. To overcome this challenge, following successful simulation runs, a special team assembled and trial tested a 2.125 in. hybrid tractor built to run in tandem configuration. New components were designed and manufactured to allow two of the 2.125 in. tractors to run in combination, simultaneously to convey CT beyond the helical lockup point. The trial was the first successful application of a 2.125 in. tandem tractor with 2 in. CT through a completion with 2.441 in. inch minimum restriction. The tractor was close to the predictions of the simulation and reached a total depth of 21,591 ft with over 4000 ft in an open hole environment and with the new tractor system pulling the CT over 1500 ft. At this depth a ball was pumped down the reel to isolate the tractor from the acid, allowing matrix stimulation treatments across the pay intervals at relatively high rates without damaging the tool. The successful deployment of the new tandem tractor in this field not only represents significant opportunity for the development of the field but has potentially far reaching global applications. The broad implications include the possibility of interventions in existing mega-reach oil producer wells with relatively small bore completions.
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DIET: An Integrated Approach of Getting the Right Data and Maximizing Its Value
Authors H. Al-Kharaz, M.Z. Farooqui, A.M. Ansari, D. Blackall and M. MartinWell and reservoir surveillance data gathering activities can present a number of logistical challenges and operational risks associated with well intervention work, especially in offshore sour gas fields. This paper describes an approach adopted by RasGas Company Limited (RasGas) to reduce these risks by implementing a workflow that facilitates full integration of the acquired data to maximise its value and improve the understanding of well/reservoir performance. Hence, the workflow is used to arrive at a need-based strategy to plan, design and execute yearly well/reservoir surveillance programmes. The need for early well and reservoir performance data when a new gas field is placed on production often necessitates a calendar-based and broadly applied surveillance programme to develop reservoir deliverability and well productivity trends across the field. These baseline data are used to proactively identify and quantify potential threats to well productivity and production sustainability from issues such as skin build up from scale or condensate banking, unexpected formation water production, corrosion damage, etc. Once the sufficient baseline data set has been acquired, there is a need to develop an optimum approach towards well and reservoir surveillance programmes. This ensures that surveillance programme is focused on delivering truly needed data while reducing the risks inherent to well intervention activities. RasGas achieved this optimisation through development of a workflow called “DIET” (Data Integration and Evaluation Technique). Implementation of DIET has significantly reduced the reliance on a set-frequency logging strategy, thus reducing overall well intervention job counts, costs and risks. In addition to integrating all relevant data for single well evaluation, the DIET workflow is also being expanded to enable field-wide data integration.
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Acoustic Velocity Measurements and Interpretation for Challenging Fluid Systems
Authors E. Lewis, G. Odikpo and B. DindorukAcoustic velocity can be measured with a high degree of accuracy making it an attractive method for extracting related thermodynamic properties. Technical improvements were made to measure acoustic wave velocities in fluid samples over a range of temperatures, pressures, and fluid properties. The simplicity of this technique relative to conventional PVT measurements makes it a fast and reliable means for obtaining some of the data needed in petroleum engineering calculations. The primary objective in this study is to determine whether the designed apparatus is suitable for measuring compressional wave velocities in fluids commonly encountered in oil and gas operations. Additionally, the potential of the device to be used as a QC tool to accompany conventionally determined PVT properties was also studied. A robust experimental design allows for the determination of acoustic wave velocities at elevated pressures and temperatures and includes the ability to homogenize and recondition samples. For experiments involving heavy, viscous oils – especially those containing dissolved gas – this capability is particularly important.
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Active Field Development without Harm to Saudi Arabia's Ecosystems
Authors J. Arukhe, S. Al Ghamdi, S. Hanbzazah and A. AhmariReliably and responsibly meeting global energy demands is often a challenge involving a delicate balance between environmental stewardship and operational excellence. One such challenge involves the protection of the delicate Arabian Gulf coast ecosystem while developing an enormous hydrocarbon reservoir that lies underneath. The scope of the paper is to reflect on the lessons resulting from the design and execution of safe rigless activities leading to a prolific field development. The field’s development is a crucial element in the company’s energy supply strategy with a significant increment to the anticipated production levels. The approach adopted involves the optimum use of limited drill site space for surface well testing equipment layout. The testing methodology involved smokeless deliverability tests with reduced environmental impact. The design considerations include averting uncontrolled hydrocarbon release to the environment through processing and treating for H2S and water on dedicated process tanks. The design included significant improvements in air flow systems and enhancement of crude characteristics for smokeless flare enhancement. Field data of critical variables was continuously evaluated in after action reviews for applicable technology solutions. Specifically, the results include the successful execution of a rigless campaign involving over 60 producers. Although oil well deliverability testing of conventional producers seems commonplace in the oil field, managing ecological, operational constraints, close well spacing, heat radiation, pollution, and a potential release of H2S to the environment from sour crude requires a painstaking commitment to ensure sound engineering and environmental practices.
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Innovative Integrated Process Scheme for Native CO2 Recovery
Authors C. Weiss, F. Pousse, K. Ghodasara, M. Linicus, E. Jüngst and S. FränkleWhile considering CO2 emission from a gas plant, native CO2 significantly contributes to the total amount. Capturing this native CO2 can reduce a lot the green house gases emission and captured CO2 can be valorized for Enhanced Oil Recovery. Due to this, Oil and Gas operators are more and more interested in improving native CO2 recovery technologies. Usually when natural gas contains both CO2 and H2S, they are removed together and sent to Sulfur Recovery Unit resulting in a tail gas containing mainly Nitrogen and CO2. CO2 can then be separated by use of solvent (using MEA e.g.). TOTAL and Air Liquide have developed and patented an innovative process scheme recovering native CO2 and reducing the operating and investment costs. Claus unit fed with pure oxygen instead of air leads to a tail gas stream, containing mainly CO2 and H2. Then, CO2 purification unit allows recovering a CO2 rich stream with purity even up to 99.9%. This purification unit can be either membrane, cryogenic or adsorption technologies, or a combination of them. This paper also discusses about the integration of Oxygen-based Claus technology (OxyClaus), tail gas treatment unit (TGTU) and CO2 purification. The scheme has been studied in detail for specific application to optimize the overall integration. It has been also compared to conventional CO2 capture scheme to highlight its benefits leading to significantly lower CO2 recovery cost. This scheme contributes in many aspects to the current technical knowledge which may include low-cost CO2 capture, use of pure oxygen in the Claus, CO2 purification for EOR etc. Other benefits also include the size reduction of the Claus/TGTU, production of nitrogen stream to be valorized and separated H2-rich stream from CO2 purification unit. This paper will comprise the overall scheme description and discuss some results for the specific case study.
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Differentiating Between Oil-based Mud Filtrate and Multiphase Formation Fluids Using Wireline Formation Testing Techniques: Case Studies from Saudi Arabia
Authors M. Al-Harthi, F. Kelly, and F.N. Enezi and W. SoleimanIn wireline formation testing and sampling, a difficult and long standing challenge is the differentiation between mud filtrate and formation fluids, especially in oil-based mud (OBM) (diesel/water mixture) and multiphase formation fluids (oil/formation water) environments. This challenge can cause ambiguities during the interpretation of downhole fluid properties and determination of the contamination levels before sampling. Often, during the sampling process, fluid mixing increases fluid property sensor noise and causes difficulties with accurate fluid identification and contamination levels. Consequently, noisy sensor readings are attributed to the transitional phase of sampling and pertinent information is ignored. This paper presents several examples where fluid mixing has occurred. A high-resolution volumetric densitometer is used to accurately identify fluid properties. It monitors the change of frequency of a vibrating tube immersed in the fluid sample. Because of the high accuracy of this technique, it is also possible to determine additional fluid properties, such as density, water salinity, and fluid compressibility. Furthermore, new processing methods are illustrated, which provide a clearer understanding of flow behavior and allow more accurate estimates of fluid contamination. The examples are verified using fluid volumetrically maintained at the reservoir pressure and temperature (PVT) lab results comparing the downhole real-time fluid property measurements and interpretation with the actual fluid samples recovered.
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Rediscovering the Reservoir by Using New Logging Techniques in Mature Fields
More LessMature fields account for 70% of global oil and gas production. However, in many of these fields logging data has not been collected in years. During this time, new logging techniques and technology have advanced to the point that it may be cost effective to re-log these wells and ‘rediscover’ the reservoir; providing new resources and vastly improved economics.
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High-Resolution Distribution of Organic Matter in Carbonate-Rich Oil Shales Controlled by Climatic Cycles and Depositional Environments
Authors B. Caline, D. Dessort, I. Billeaud, S. Cantaloube, P. Allix, J.M. Krafft and R. Le Van Loi and D. DuclercThe objective of this joint sedimentological and organic matter study was to document and understand the vertical heterogeneity of organic matter distribution of an oil shale interval which belongs to the lower Muwaqqar Fm in Jordan. The high resolution logging of organic carbon using new pyrolysis instrument reveals the cm-scale rhythmic bedding of the oil shale deposits. Cyclostratigraphy based on recognition of Milankovitch cycles appears to control the alternation of rich and lean organic layers within this carbonate interval.
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Advanced Technologies For Produced Water Treatment And Reuse
Authors A. Hussain, J. Minier-Matar, A. Janson, S. Gharfeh and S. AdhamProduced Water (PW) is the highest volume liquid waste stream generated by the petroleum industry. Historically, the treatment of PW has been limited to free oil and suspended solids removal, using physical separation technologies, and injection in disposal wells. However, because of new regulations combined with geological restrictions and local water scarcity, the drive to have a greater fraction of the PW more extensively treated and ultimately reused is increasing. Moreover, the growth in the application of water intensive processes to extract unconventional oil&gas resources, in particular in shale plays and oil sands, has increased the need for cost-effective treatment and reuse of PW to reduce fresh water uptakes. Therefore, the petroleum industry is investigating new PW treatment technologies given that the physical separation technologies traditionally used in the past are, in most cases, not capable of producing water of suitable quality to replace fresh water uptakes. This paper presents the results of a laboratory investigation carried out by the ConocoPhillips Global Water Sustainability Center (GWSC), where various treatment processes (membrane processes, membrane-bioreactors (MBRs), membrane distillation (MD) and ozonation) were evaluated as treatment methods for PW from different oil&gas fields. The key conclusions of this paper are: • Membrane Processes and Thermal Evaporators are currently operating within the petroleum industry in full scale PW treatment and reuse applications. • The preliminary results of investigations performed by GWSC confirmed the potential of Membrane Filtration, MBRs and Ozonation to treat PW and produce an effluent suitable for reuse. Membrane Distillation may have potential in the longer term. Further investigation is ongoing. • If successfully implemented, the above technologies will contribute to provide the petroleum industry with a broad range of technologies to cost-effectively treat and reuse PW.
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SHE&S Excellence and Innovation for the Barzan Onshore Project
Authors R.E. DeHart II and J. BrandThe Barzan Onshore Project is being developed by Barzan Gas Company Limited, a joint venture between Qatar Petroleum and ExxonMobil Barzan Limited, with RasGas assigned to develop and operate the facilities on completion. The Engineering, Procurement and Construction (EPC) work is being carried out by JGC as the prime contractor. JGC has subcontracted the construction execution of the work to eight major sub-contractors. The project has achieved over 90 Million Safe Man-hours since July 2012 when the one lost time incident project to date occurred. The workforce is approaching 29,000 persons from multiple countries. The paper describes the overall SHE&S Management System as a three-tier model based on the EPC contract in which there are 211 SHE&S contract-related deliverables (in eight general categories) measured monthly via the SHE&S Work Activities Schedule. The system pertains to all parties (RasGas, JGC, sub-contractors, vendors, suppliers, et al.) and this rigorous monthly accounting helps drive overall SHE&S performance. The contract combines a highly prescriptive as well as goalsetting approach, which to date has delivered a great foundation to build and sustain SHE&S performance at site. Within the paper, some of the key leading and lagging indicators are reviewed to demonstrate the correlation between the scope of work, stage of project execution, progress and key injury trends occurring at the site. The indicators are actively utilised on the project, especially the leading indicators to drive and sustain SHE&S performance. Six stellar areas and six challenging areas are also reviewed. The stellar areas demonstrate some of the key best practices that are implemented on the project and are producing strong results. The six challenging areas demonstrate some of the complex problems on the project and the methods that are used to improve these problem areas and help ensure that sufficient risk reduction measures and actions are being implemented. Overall SHE performance on the project continues to be strong although there are daily challenges. These challenges are overcome by a strong management commitment as well as a worker-focused programme that continually demonstrates care and concern for the project’s most valuable asset, the workforce.
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Integrated Gas Management to Maximize Well Potential and Reserves within a Mature Oil Field
Authors E. Gunasan, A. Pearce and C. BlondeauTotal has been operating oil and gas production from a series of heterogeneous reservoirs offshore Abu Dhabi since 1974. Today, maximizing oil production is critically dependent on how the facilities can cope with handling the associated gas and water rather than treating the oil itself. The nature of these 40-year old facilities and the variable and sometimes erratic performance of individual wells mean that decisions have to be made on a daily basis regarding allocation of available gas for injection into the reservoir for enhancing oil recovery versus its use for gas lift. The decisions have to be made on the basis of predicted incremental oil but in the context of surface gas and water handling constraints. This paper will describe how a holistic approach seamlessly integrates historical reservoir and well behavior, the daily surface constraints and provide a means to easily and automatically allocate any gas that is available to optimize oil production. A well prioritization list is updated regularly to explicit to which well gas should be allocated and whether it should be used for lifting high water-cut wells or injecting into the reservoir to provide tertiary gas injection for enhancing oil recovery. This approach has led to a virtually constant level of oil production over the past 3 years; which for a mature oil field that would normally decline at 10-15% per year has been a major success. In addition, the successful full-field Tertiary Gas Injection project has resulted in a recovery factor of over 50% in the main reservoir; a top class achievement for a carbonate reservoir. Today, 15 years after implementation, the TGI effect contributes over 30% to the oil production from the reservoir.
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Effective Wells Corrosion Mitigation in Two Major Middle East Fields: A Case Study
Authors M.S. Alzahrani, K.X. Senusi, D.R. Lewis, A.Y. Aty and F.A. ShinaiberThe focus of most waterflood or pressure maintenance projects is on the performance of the production and injection systems to ensure maximizing field rates and efficiencies. Yet there is a third leg to this operational triangle: the water supply system including wells and gathering system. This paper presents a case study of operational strategies and programs developed from experience from mature Field “B,” and then translated to a revitalized re-started Field “F.” These strategies include the use of tubeless completions of the water supply wells to maximize the water production rate and the subsequent implementation of a “build-down” strategy consisting of the installation of smaller casing sizes to isolate impaired casing sections and well monitoring with corrosion logs to address casing integrity issues. Over time, the casing profiles became smaller, the rate of casing integrity issues accelerated and the overall supply well rates could not meet the increased injection demand. These casing integrity issues (up to 60% metal loss in some wells) necessitated a shift in strategy from the mechanical “build-down” to a mitigation strategy to extend the life of the existing supply wells. The “build-down” strategy was effective from 1975 to approximately 2006 in isolating casing integrity issues. The initial chemical squeeze inhibition campaign completed from 1979 to 1981 floundered on the monthly treatment requirements and the attendant high cost for these treatments. As casing profiles become smaller over time, a revamped corrosion inhibitor treatment program was completed quarterly and has been found to extend the well service life by 7 years so far. Furthermore, this case study will review the efficiency of the use of the same corrosion mitigation squeeze strategy in the revitalized Field “F.”
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Holocene Intertidal Microbial Mats of Qatar and Their Implications for Petroleum Source Rock Formation in Carbonate-Siliciclastic-Evaporite Systems
Authors M. Słowakiewicz, R.D. Pancost, L. Thomas, M.E. Tucker, S. Mey Didi-Ooi and F. WhitakerOrganic-rich mesohaline microbial mats occur in the intertidal zone of a lagoonal area developed to the lee of a coastal spit in Mesaieed, Eastern Qatar. The mats grow on a substrate of seagrass-rich carbonate mud with cerithid and monachid gastropods and other small bioclasts, reaching a thickness >3.5 cm. The mats are well laminated with different microbial communities, from cyanobacteria to sulphur bacteria, reflected in the distinct colour changes from green to pink to brown. The mat layers contain spheroids of dolomite, the precipitation of which was plausibly mediated by bacteria. The lipids reflect the biomass of the principal mat-building phototrophic and heterotrophic microorganisms. A variety of hydrocarbons, including n-alkanes, diploptene, and isoprenoids such as phytane, phytene, phytadiene and squalene were detected, in varying concentrations amongst the particular mat layers. In particular, n-heptadecane, likely derived from cyanobacteria, dominated the n-alkane distribution at a depth of 0-0.1 mm. The concentration and abundance of n-alkanes increase with depth through the mat, likely representing the early diagenetic initiation of hydrocarbon generation. Therefore, understanding early diagenetic organic matter alteration and preservation in marine mixed carbonate-evaporite-siliciclastic systems, as well as the processes operating in the early stages of diagenesis, could improve understanding of the hydrocarbon potential of such systems. This will help considerably in the prediction of hydrocarbon occurrence in frontier, as well as mature, petroleum carbonate-evaporite basins.
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Using Wireline Formation Tester Pressure Survey to Validate and Fine-tune Model Building: A Case Study for a Multi-layered Mature Reservoir
Authors S.I. Badusha, A.M. Qamber, S. Al-Rashdan, A. Safar, A. Mahato and S. DeWireline Formation Tester surveys are routinely performed for pressure profiling in all new wells. These surveys are being extensively used to identify contacts, cross communication etc. The information is updated and integrated for a full field perspective so that depletion trends, communication across faults, and presence of sub-layers within the main sand lobes are identified, validated and mapped. This data set is acquired over time, against a well laid out strategy and against all the sands. As a precursor for building a model in a multilayered mature oil field of Kuwait, the collected data were analyzed to draw interesting and operationally important conclusions.The study reinforced the sub-layering classification followed in the field on a broader scale; however in a few instances, marked anomalies were noted. The existing sand layering scheme was re-visited and corrections applied by adjusting the layer tops in those wells. Multiple pressure points across adjacent sub-layers with close pressure regime were grouped and re-grouped and plots were generated. The layers followed the existing geological layering scheme; but in some instances, the plots indicated a different picture of the extent of these sub-layers. This type of validation of layering scheme of the static model gave important insights during upscaling for the dynamic model. Analyses of the plots were carried out in different segments for well clusters across faults. The plots uncovered important information about the nature of the faults. Conclusions drawn from these plots are planned to be used for supplementing Pressure Transient Analysis information during history match.
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Experimental Simulation of Hydrocarbon Expulsion
Authors L. Schwark, M. Stockhausen, R. Galimberti and R. EliasLaboratory studies simulating thermal maturation of source rocks to generate and expel oil/gas differ from natural conditions. Amounts and compositions of products deviate between experiments and those found in natural petroleum source, carrier and reservoir rocks. Experimental data used in numerical models simulating oil/gas generation/expulsion thus seem to require adaption, causing significant uncertainty in present petroleum systems analysis. We designed and tested a procedure to simulate laboratory generation and expulsion of hydrocarbons under conditions most similar to natural conditions.
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Multifunctional Boronic Acid Crosslinker for Fracturing Fluids
Authors D. Loveless, J. Holtsclaw, J.D. Weaver, J.W. Ogle and R.K. SainiBoron-crosslinked guar-based fluids are widely used in hydraulic fracturing applications and, unlike metal-crosslinked fluids, they are tolerant of high-shear conditions and often result in superior fracture conductivity because of better post-fracture cleanup. Guar is a natural polymer that contains insoluble residues, which can cause fracture conductivity damage. To help minimize this damage, lower-concentration polymer crosslinked fluids have been developed (18 to 20 lbm/1,000 gal). This approach is limited to polymer loadings above the polymer critical overlap concentration (C*). Below this concentration, unstable crosslinked gels are likely. The development of a new technology that permits the use of crosslinked guar at concentrations near or below C* is presented in this paper, as well as initial results obtained from field testing. Well-behaved crosslinked fracturing fluids have been formulated at guar concentrations at 8 to 10 lbm/1,000 gal with this technology. This new technology is based on the use of a water-soluble long chain polymer that includes boronic acid moieties, which can crosslink guar polymer below C* concentration. The chemistry of this polymeric crosslinker and the resulting gels are similar to that of conventional borate crosslinkers. Synthesis and optimization of the polymeric boronic acid crosslinker is presented, along with rheology and conductivity studies. This new technology provides the fracture design engineer with a new crosslinked fluid system that can reduce the potential for conductivity loss resulting from fracturing fluid damage by reducing the amount of guar gum (and insoluble residue) required to fracture a well by half or more.
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Reservoir Quality Assessment from Clay Mineral Distribution in the Neogene of North Kuwait
Authors P. Kumar Mishra, B. Hussain Akbar, K. Ahmed, H. Ferdous, L. Javier, P. Kumar Choudhary and F. AbbasThe Neogene clastics illustrate wide variations in reservoir quality in the North Kuwait fields .There are two main controls on reservoir characteristics within the sedimentary succession namely matrix content and carbonate cement abundance. The detrital clay and dolomitic matrix content controls reservoir quality, with the poorest permeability and porosities associated with deposits containing abundant detrital matrix. Pervasively cemented sandstones will result in relatively low porosities (c.20-25%). However, subsequent partial dissolution allowing tortuously connected macro pores has resulted in the retention of higher than expected permeability (c.1000-10000mD). Samples that have undergone localized replacement of detrital clay by calcite generally have lower porosities (c.10-20%) and permeability (c.4-30mD ;). Coarser grained and well sorted (generally clean) samples typically having the best reservoir quality. The various pore types typically occur across all reservoir layers and facies associations, with the notable exception of primary interparticle macropores, which have not been identified within the interdistributary bay/lagoon facies association. However, intra-clay and intercrystalline pores generally occur as the dominant pore type within the non-channelised deposits (eg. Lower shoreface), while primary interparticle macro pores are the dominant pore type within channel sandstones. In terms of reservoir quality, the best quality is generally found in clean channel sands. As expected the poorest reservoir quality is found in deposits with no or limited macropores, which typically have intercrystalline and intra-clay pore types. The controls on reservoir quality also vary between facies association. The facies associations with high matrix abundance, such as floodplain, interdistributary bay/lagoon and lower shore face, are associated with the poorest reservoir qualities. In contrast, the reduction in reservoir quality associated with calcite cementation only occurs within clean Channel sandstones .The distribution is considered primarily by reservoir layer and then in terms by the facies associations within those layers. The total smectite, illite-smectite and palygorskite content varies across the field , with a low content in the north and centre (2-4.6%), a moderate content in the east (6.7-7.3%) and a high content in the south (11.2-14.4%). The Horizontal permeability ranges from 0.44mD to 10000mD with a geometric mean of 2026mD, whilst helium porosity ranges from 2.8% to 42.5% with a mean of 33.1%. There is no linear relationship between permeability and porosity, with a wide range of porosities for samples with similar permeabilities. This poorly defined porosity-permeability relationship is probably the result of authigenic carbonate and detrital feldspar dissolution, which has locally enhanced secondary macro porosity network. Often some of these secondary macropores are localized and may not be connected to the rest of the pore system; hence helium porosity increases relative to permeability. Dissolution, while common, varies in intensity which gives rise to the wide variety of porosities identified within the deposits.
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Recent Advances in Seismic Monitoring of Thermal EOR
Authors A. Mateeva, J. Lopez, K. Hornman, P. Wills, B. Cox, D. Kiyashchenko, W. Berlang, H. Potters and R. DetomoWell-planned and executed reservoir surveillance has proven to add significantly to the production and ultimate recovery of hydrocarbons, notably in areas of Improved and Enhanced Oil Recovery (IOR/EOR). Recent technological advances in the area of data acquisition and integration have led to increased use of well and reservoir surveillance data to optimize such processes. In the case of thermal EOR, one of the most important subsurface uncertainties impacting performance is heat and steam front conformance, both vertically and arealy. This paper illustrates new geophysical technologies used for monitoring various thermal EOR recovery strategies in The Netherlands, Canada, and Oman. We focus on permanently buried seismic sources and receivers, refraction seismic, down-hole seismic, and the newly developed Distributed Acoustic Sensing (DAS) to enable low-cost and non-intrusive seismic surveillance. These technologies are not without challenges, but our field trials indicate they have the potential to broaden the successful application of reservoir monitoring onshore.
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Channel Fracturing Enhanced by Unconventional Proppant Increases Effectiveness of Hydraulic Fracturing in Devonian Formations of Russia’s Oilfields
Authors R. Kayumov, A. Klyubin, A. Konchenko, A. Yudin, A. Khalzov, V. Firsov, E. Nikulshin, Z. Kaluder and S. SitdikovThe Volga-Urals basin is one of the largest oil-producing regions in western Russia. The most prolific wells are producing from Devonian formations characterized by light crude oil with high bubblepoint pressure. Today, most of the Devonian reservoirs are depleted and produce at bottomhole flowing pressure below bubblepoint pressure, which yields multiphase and non-Darcy flow in hydraulic fractures, drastically decreasing production. As a result, conventional hydraulic fracturing treatments are less effective. To regain fracturing treatment efficiency, the restrictions to hydrocarbon flow inside the fracture must be minimized. To account for this, a new method of fracture conductivity generation was introduced. Channel fracturing creates open pathways inside the fracture, enabling infinite fracture conductivity. Channels are created by discontinuous proppant feeding at surface into viscous fracturing fluid. Dissolvable fibers are added to the slurry to separate proppant structures and prevent them from settling during treatment. Proppant structures act as bridges inside fractures; voids between them are essentially stable channels connected along the entire length of the fracture. While channel fracturing has already been implemented successfully in many places around the world, the fracturing conditions of Volga-Urals Devonian formations were still new for this technology. The Volga-Urals region is well known for high tectonic stresses and low fracturing-fluid efficiency. While channel fracturing treatments are being designed and pumped in a regime without tip-screenout (TSO) in other locations, channel fracturing treatments in Devonian formations often showed significant TSO. Production analyses showed consistent productivity increases, and in most cases, 2 folds higher compared with offset wells where conventional fracturing technology was used. After the success of the pilot campaign, proppant flowback was resolved by incorporating a rod-shaped proppant as a tail-in stage of channel fracturing schedules. The nonspherical shape of the proppant increases internal friction between the particles and mechanically holds them in place. In addition to improving proppant flowback control, the combination of technologies maximized conductivity of the near-wellbore area which connects channels and the wellbore. The success of more than 30 of such fracturing treatments expanded the pool of candidates for channel fracturing with rod-shaped proppant to meet the challenges of similar complex geological conditions.
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High-Resolution Sequence Stratigraphy Analysis in a Carbonate Reservoir from Borehole Resistivity Images: A Case Study from Tarim Basin, West China
More LessFormation heterogeneity due to fractures, vugs, and mixed lithologies complicates the characterization of carbonate reservoirs. The lithology distribution is controlled by multiple factors, such as sediment source, depositional environment, and diagenesis. In addition, fracture development is influenced by lithology, burial depth, local structure, and far-field stress. High-resolution sequence stratigraphy is one of the advanced methods that can be used to solve the lithology challenge. The method combines core analysis, conventional logs, outcrop studies, and seismic data. However, the analysis results are frequently constrained by the low resolution of the seismic and conventional log data and by limited core data. A new workflow for high-resolution sequence stratigraphy analysis integrates borehole resistivity images with seismic, log, and core data. First, the borehole resistivity images are compared with core data, and the depositional facies are identified from calibrated resistivity image data combined with multiple-domain data. Second, sequence stratigraphic surfaces are identified from seismic and image data and the thicknesses of crossbedding and sequence cycles are used to classify the strata stacking patterns. Finally, the distribution of depositional environments within a sequence stratigraphy framework is analyzed by integrating the sequence stratigraphy patterns with seismic attribute maps and petrophysical log interpretation to predict the sweet spot. This new approach was implemented in Block A8 of the Tazhong uplift in the Tarim basin. Six different depositional facies were identified from the core data from three wells and applied to an additional four wells and to noncored intervals. Isopach maps of the first long term sequence cycle were used to estimate the size of buildups (reef, mound) and predict the vug distribution. A recently drilled well confirmed the analysis results. This workflow can be applied to similar thick carbonate reservoirs in the shoal-reef margin of a carbonate platform.
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ESP Well Surveillance using Pattern Recognition Analysis, Oil Wells, Petroleum Development Oman
Authors A. Awaid, H. Al-Muqbali, A. Al-Bimani, Z. Al-Yazeedi, H. Al-Sukaity, K. Al-Harthy and Alastair BailliePDO is managing some 850 Electrical Submersible Pump (ESP) systems scattered across North & South fields, which is continue to grow in the next five years business plan. All ESP wells have real time down-hole sensors that measures intake and discharge pressures, intake and motor temperatures, vibration and current leakage. The oil producing fields are equipped with real time data transmission system where several data measurements; down hole (such as pump intake and discharge pressures and temperatures) and surface (such as volts, amps and frequency) are transmitted directly from the well site to the gathering stations, central control rooms and even to the engineers’ desktop. At present, PDO is deploying an integrated smart tool which will monitor, control, and optimize oil production and ESP performance to the various disciplines involved in oil production and optimization like Reservoir and Petroleum Engineers, Programmers, and Field Operation Teams. However, in order to enable these modern well surveillance systems, which often produce an overwhelming quantity of information but the data is often misleading or difficult to interpret, establishing the Pattern recognition of the trended real time data is key to make the software intelligent enough to be effective to the work places. This paper will demonstrate how precise ESP, well and reservoir performance can be predicted from simple physical relationships and how these relate to the trends of surface and downhole data. A number of real field examples of data trends will be shown to illustrate how a proper understanding of these patterns will allow prompt ESP troubleshooting and ensure the correct actions are taken. The results are correlated with equipment pull and inspection reports to validate the diagnosis. Pattern recognition trends and analysis will be presented for common problems such as hole in tubing, shut in at surface, ESP wear, blockage at pump intake, debris in pump, broken shaft, change in reservoir pressure, blockage at perforations, etc. A proper understanding of these trends will allow the correct settings of alarm and trips and assist in the implementation of semi-automated well surveillance and diagnostic system which being currently deployed in the Company. A pattern recognition analysis check sheet will be included in the paper to allow users to quickly interpret data trends and diagnose well, ESP and reservoir performance problems.
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GTL Efficiency
By A. Al-TamimiA number of key parameters have been used for defining the efficiency of GTL (Gas-to-Liquids) process. The most commonly used bases are Carbon Efficiency (CE) and Thermal Efficiency (TE). This paper discusses the definition of each of them and the significant developments that have occurred and have been expected on the key focus areas of GTL efficiency improvement. Both CE and TE should be maximized to the extent of technically feasibility and economical justification to ensure responsible and sustainable utilization of natural resources. Nowadays, the GTL technology CE and TE are considered drawbacks of the GTL technology and as a consequence considerable efforts are being made by technology developers to reduce the inefficiencies. The current generation of the GTL technology has a typical plant wide CE of 70-75 % and a typical plant wide TE of 57-61%. Although GTL efficiency is still low compared to conventional refineries and LNG plants, it has been improved significantly over the last two decades. Further improvement can be expected over time as the GTL technology has not gone through the same degree of technological improvement as the conventional system. Advances in GTL technology are projected to increase the efficiency within the next decade as such it would be comparable to conventional refineries and LNG plants that have CE and TE of around 90% and 73% respectively.
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Syngas Technologies
By J. Al-MullaThis paper will discuss the comparison between the three leading Syngas manufacturing technologies; Partial Oxidation (POX), Autothermal Reforming (ATR) and the Steam Methane Reformer (SMR) technology. Also, this paper will discuss the development of the Catalytic Partial Oxidation COPox syngas technology. The discussion will focus on illustrating the general syngas chemistry of each technology and where the COPox process fits into the spectrum of syngas technologies. It will also discuss the application of the first two technologies in commercial plants and some of the critical operating parameters that can influence the performance and the efficiency of syngas production such as, feed gas composition, operating temperate and pressure. Syngas can use in the Fischer-Tropsch and methanol process, as fuel, or as an intermediate for chemical production. Syngas treatment and removal of sulfur, NH3, soot and HCN containing compounds is essential to the final application of the gas. This paper wills discuss the effect of the impurities in the syngas.
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A Fresh Look at Thin-Bed Prospectivity within Conventional Shallow Water Clastic Plays—Implication for Significant Bypassed Pay
More LessThin-bedded sands in shallow water clastic deposits are widely neglected as exploration targets simply due to conventional wisdom that focuses more on the “charismatic” blocky clean sand packages. In addition, the lack of a strong, characteristic motif on the log response and complexity in quantitative characterization of these thinly laminated sequences leads to even less attention to such sequences as potential targets. This can have significant impact on the certainty of realistic reserve calculation in exploration and development planning in regions such as Southeast Asia where these thin-bedded sands are a considerable portion of the stratigraphic column. This study has two phases; in the first phase, a novel technique is presented to identify and quantify thin sand laminations using borehole images and core. Both borehole image and core data is converted to binary data representing shale and sand facies. Then these images are used to quantify the total thickness of thinly-laminated sands on the basis of specific cutoff values. In the second phase, a comprehensive analysis of a local present-day analogue determines the possible hydrocarbon storage capacity of thin-bedded deposits. This is accomplished through an area/volume approach. In this approach, after locating the pertinent locality within the depositional environment that can be considered as the equivalent to the subsurface section under study, the sand volume vs. area of thin-bedded heterolithic facies is computed. This is used to estimate the storage capacity of these facies at the field-scale. Additionally, the storage capacity is compared to the capacity of channelfill sands as conventional targets in the same setting. Results of this study show that the new technique using high-resolution borehole images can successfully identify and quantify thin-bedded sands, and results have an excellent match with core data. Also, the core results confirm that these deposits have sufficient reservoir quality (porosity and permeability), particularly for gas production. This work demonstrates that, contrary to conventional belief, the storage capacity of thin-bedded sands can be significantly high and sometimes may even exceed that of blocky channel or mouth-bar sands. This implies that substantial quantities of pay are continuously bypassed in basins where these sequences are expected.
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Pore Structure Characteristics of Non-Marine Shale in Ordos Basin, China
More LessUnlike marine shale, the non-marine (lacustrine) shale deposits are with frequent sand and mud interbed, large gross thickness, interlayers development and etc. In order to study reservoir properties, adsorption, permeability, porosity, gas storage and migration of such shale, experimental study of porosity character with the core sample of Mesozoic Triassic Yanchang Formation shale in Ordos Basin of China and contrastive study of this non-marine shale porosity characters and marine shale porosity character in north America and China were integrated in this paper. In experimental study, high pressure (up to 200 MPa) mercury porosimetry analysis determined the porosity, pore diameter and its size distribution, and specific surface area; different pressure permeability tests with nitrogen medium were taken to analysis the permeability with Klinkenberg correction; SEM images were observed to characterize the micro pore structures, and to describe the geometry, connectivity and fillings of pores. By combining all above experimental result, core structure features was comprehensive analyzed and gas-bearing properties of shale was evaluated. In contrastive study, experimental and literature data of pores feature in non-marine shale and marine shale, including permeability, porosity, pore size, and SEM images, were compared to analyze the development and structure of shale porosity in different sedimentary environment. Studies show that lacustrine shale has considerable gas storage capacity, and various types of porosities were observed on SEM images. Expectable, it could get considerable gas output. However, non-marine shale with extremely low permeability has adjacent porosity (accessible porosity 2.27%) to that of marine shale, which is attributed to the poor rate of pore connectivity in non-marine shale.
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What happened to all my Gas? P/z plots in Layered Reservoirs
By F. RossP/z plots for low permeability or layered reservoirs do not yield a straight line which extrapolates to the IGIP; they are curved and deviate strongly from the theoretical straight line. Consequently, the interpretation of the P/z plot is often grossly misleading and typically significantly underestimates the IGIP, leading to erroneous production forecasts and reserve estimates. The problem with the simple P/z material balance plot is that the pressure measured using a pressure build up test is not representative of the drainage volume of the well. When P/z plots cannot be analysed quantitatively, typically a numerical reservoir simulator is used to match the shut-in bottom-hole pressures and the continuously measured wellhead rates and pressures. However, a simple multi tank material balance method can provide valuable insights into the reservoir behavior and can be used either as a precursor to, or to replace numerical simulation. This paper describes a technique that can be used for medium to high permeability reservoirs.
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Multiphase Flow Meters Trial Testing in High GOR/GVF Environment
Multiphase flow metering (MPFM) technology is gaining popularity and becoming the main well rate testing mechanism in some regions of the world. Yet, their application in measuring the flow rates of high gas-oil-ratio (GOR) and/or high gas volume fraction (GVF) wells has always been a challenge. A remote field located in the Southeastern part of Saudi Arabia commenced its production in the late 90’s from a thin oil column lying between a large gas-cap and a water aquifer. Although, 84% of the thin-oil-column producing wells are horizontal and multilateral wells with extended reservoir contact, the gas-cap gas breakthrough and production from these wells have increased gradually; resulting in an increase in the wells GOR. Currently, 35% of the wells are producing at high GOR ranging between 2,000 and 6,000 SCF/STB with a GVF reaching as high as 98%. The fluid flow rate tests of these wells are conducted through a test separator designed to handle a GOR of 2,500 SCF/STB; well below the current GOR of these wells. Such plans require identification of the most appropriate MPFMs that can operate successfully in such high GOR/GVF conditions. This paper describes the field trial test of three MPFMs under high GOR/GVF conditions of dry and wet production. The meters’ performance is compared to a portable test separator properly sized to accommodate the high gas and liquid flow rates of the producers of this field. The paper summarizes the results of this test and justifies the measurement errors in light of the operating principle of each meter. The paper also provides valuable guidelines for conducting such testing operations by building on the lessons learned from this trial test.
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An Evaluation of Production Casing Corrosion Due to Ingress of Sour Gas in the Tubing-Casing Annulus
Authors L.B. Morshidi, M.Z. Farooqui, M. A. Bugti, A. Kumar, S.K. Desai and J.L. PachecoCurrent technologies for assessing corrosion damage in downhole tubing and casing strings have several limitations. Under certain conditions, mechanical, electromagnetic and ultrasonic tools can be run inside a downhole tubing string to quantify corrosion and wall loss in that string. But these tools, at best, may only be able to qualitatively assess the condition of tubing strings which are in contact or close proximity to the tool. In wells that develop communication between the production/injection tubing and casing and allow ingress of potentially corrosive fluids into the annulus, the ability to effectively assess the condition of the production casing is important. This knowledge can drive critical decisions around well operating limits, surveillance programmes, workovers, or abandonment operations. This paper describes the results of corrosion modelling and testing conducted on carbon steel to understand the extent of internal corrosion damage expected on a production casing string when sour gas enters the tubing-casing annulus through a leak source. A wide range of conditions including various hydrogen sulfide (H2S) and carbon dioxide (CO2) concentrations were modelled using proprietary corrosion modelling software. Laboratory tests on corrosion coupons were also performed and compared to the model results. Key findings around the expected corrosion potential of production casing exposed to sour gas include: • Corrosion rates are generally low over a wide range of H2S concentrations. The presence of H2S reduces the general corrosion rate by forming a protective iron sulfide (FeS) scale. • Corrosion rates are sensitive to the chemical composition of the water in the annulus. Higher bicarbonates levels significantly reduce corrosion rates. • General corrosion rates in a sweet gas environment with CO2 can be very high because of the discontinuous nature of iron carbonate scale formed at test conditions. This case study demonstrates how corrosion modelling can be used with laboratory testing to provide reliable insight about the condition of tubulars which cannot be directly measured.
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Identification and Origin of Tar-Mat in Permo-Triassic Dehram Reservoir, Khayam Field, SW Iran
Authors A. Ahanjan, M. Khaleghi and P. HassanzadehThe Permo-Triassic Dehram Group (Kangan & Dalan formations) is a giant reservoir consisting of relatively good quality carbonate rocks in Qatar/Fars High. Recently, a well completed in the crestal part of the Khayam structure in coastal Fars area unusually yielded oil and liquid of higher asphaltene content in basal part of upper Dalan reservoir. In order to assess the origin of the heavier fluid and possible occurrence of tar mat, four gas and liquid samples from different DSTs were analyzed for their biomarker and isotope values. In addition, 27 cutting samples from the reservoir column were analyzed for their Extractable Organic Matter (EOM) and asphaltene content. The biomarker and carbon isotope data showed relatively the same lithology and depositional environment for their source rock of all fluid samples which is believed to be Silurian marine shale. The biomarker maturity related parameters such as C29Ts/ (C29Ts+C29H), Ts/C30H, C27 Diasterane/Sterane and 4-MDBT/1-MDBT ratios showed slightly lower thermal maturity for DST#3 (oil sample) relative to other DSTs (gas condensate). The Liquid chromatography of 27 cutting samples showed increased amount of asphaltene content towards the base of upper Dalan reservoir. The rock extract of around 20 m of the lowermost part of upper Dalan formation has relatively high asphaltene content (>30%) which identified as minimat or small tar mat. The high asphaltene content and the presence of slight UCM hump in Gas chromatogram of the DST3 oil sample together with the δ13CCO2 and δ13C3 values of gas samples may indicate slight biodegradation and possible incorporation of secondary microbial methane in this reservoir. Combining the data, it seems that the reservoir was originally filled with a fluid of medium maturity which then subjected to possible slight anaerobic (bio) degradation. Finally, it is charged with light fluid of higher maturity which masks the effect of possible slight (bio) degradation and resulted in deposition of asphaltene in lower part of the upper Dalan reservoir and formation of tar mat near possible water oil contact. This study showed possible occurrence of anaerobic biodegradation should be taken into account for further exploration and development and there exist possible water oil contact in lower most part of upper Dalan reservoir below the tar mat in this field.
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Virtual Outcrop Geology - A Case Study on Effective Learning and Data Preservation
Authors A.F. Ahmadzamri, A.S. Al-Mannai, C.J. Strohmenger and J.P.T. FoekenThe use of a terrestrial laser scanner to capture outcrop information has grown in popularity in recent years as a complementary method to geological field work. Laser scanning technology provides a huge volume of geo-referenced data which can be integrated with other datasets. It not only allows 3-D visualisation of the scanned outcrops but also complex qualitative and quantitative analysis of outcrop information. Light Detection and Ranging (LiDAR) technology was used as the basis for development of an interactive 3-D stereoscopic module of ancient outcrop analogs for Khuff Formation deposited in Eastern Arabian Peninsula. Seven of these outcrops, located in Wadi Bih and Wadi Hagil (Ras Al-Khaimah, U.A.E.) and representing carbonates of the Permo-Triassic Bih, and the Triassic Hagil and Ghail formations were captured using LiDAR technology. In order to obtain the highest quality dataset for visualisation purposes, a terrestrial laser scanner with mounted calibrated digital camera was used to capture outcrop information. The outcrops show lateral and vertical facies variations and stacking patterns comparable to Khuff Formation carbonates of the subsurface of the Middle East. Thicker-bedded, shallow subtidal, high-energy grain-dominated carbonates developing around high-frequency maximum flooding surfaces and thinner-bedded peritidal, low-energy mud-dominated and often microbial-laminated carbonates underlying parasequence boundaries and high-frequency sequence boundaries are features that can be well observed in this dataset. Structural features such as fracture networks, collapse features, vertical low-offset faults and mechanical stratigraphy observed at the outcrops are also captured and documented to help understand fluid flow behavior. All supporting geological interpretation and information are linked interactively to the LiDAR dataset using point-and-click menus to enhance its effectiveness. The 3-D virtual product captures the valuable knowledge of LiDAR scanned outcrops in a fashion that can be used for self-study, training, and pre-field trip and workshop discussions.
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Utilization of Onsite Nitrogen Generation Technology as a Replacement for Conventional Liquid Nitrogen for Unloading Wells: A Novel and Cost Effective Alternative with Less Carbon Footprint on the Environment
More LessNitrogen gas is one of the important consumables in demand in high volumes in the upstream oil industry. One of its regular uses is in the nitrogen unloading wells during kickoff operations to liven dead wells. Conventional methods use liquid nitrogen stored and transported in specially insulated vessels to be pumped into wells using sophisticated cryogenic pumps and equipment. Cryogenic equipment that operates at very low temperatures, poses several safety hazards such as causing cold burns when skin comes in contact with a severely cold object (liquid nitrogen is at -196 °C). This technical paper presents the successful utilization of in situ generated nitrogen gas at a wellsite as a replacement of the conventional requirement of liquefied nitrogen, storage and transportation system for liquid nitrogen, and cryogenic pumps and equipment for pumping nitrogen into the well. The paper will discuss briefly the membrane technology used to produce clean nitrogen at wellsites by drawing atmospheric air as the raw input; and the advantages of the continuous nitrogen generation technology over the conventional liquid nitrogen system.
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Helium 2 - A New Dimension to Energy Resources
By M. Al-HarbiQatar is destined to be the world’s largest helium exporter by 2013 when the world’s largest helium refining unit begins to produce its first drop of liquid helium. The new unit Helium 2 facility will join the existing Helium 1 facility to provide more than a quarter of worldwide helium sales. On behalf of RasGas and Qatargas owners, the RasGas and Qatargas Helium 2 Project Teams have built a state-of-the-art facility where crude helium is extracted from six Liquefied Natural Gas (LNG) mega trains. Crude helium is transported by pipeline to a helium recovery unit, refined to 99.999 percent Grade-A purity, liquefied, and loaded into containers for shipment to three main customers. The new extraction facilities will also include equipment to oxidise trace amounts of methane from the feed stream in order to minimise the project’s environmental footprint. Qatar’s helium is produced as a by-product from the LNG trains. Capitalising on economies of scale, large volumes of helium are extracted for export, further strengthening the market position of the project’s shareholders and providing flexibility to meet future demands. Helium is used in various applications such as medical scanners, academic laboratories, diving, space exploration, and leak detection. In cryogenic applications where extremely low temperatures are required, there are no known substitutes for helium, making it a strategic long-term resource.
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Determination of Reservoir Permeability Based on Irreducible Water Saturation and Porosity from Log Data and Flow Zone Indicator (FZI) from Core Data
Authors M. Fazel Alavi, M. Fazel Alavi and M. Fazel AlaviThe Flow Zone Indicator (FZI) core analysis method is an accurate approach for defining different Hydraulic Units (HUs) in a well with core data, and finding accurate k-φ relations for each HU according to k = Cn φxn. Determining HUs in un-cored wells from logs or geological information is the main challenge for the FZI method. Several methods have been proposed for finding HUs in un-cored wells. In many approaches, HUs are correlated with log attributes in cored wells, and this relationship is applied to un-cored wells. However, since a persistent relationship between log attributes and FZI does not exist in all litho-facies, this does not always give reliable results. Based on a study of core and log data from several carbonate reservoirs, a practical, straightforward technique designated as the FZI-SWPHI (Flow Zone Indicator – Irreducible Water Saturation and Porosity) method is proposed. A theoretically sound relationship between FZI and Swir φeexists for a sedimentary environment. To find this relationship, FZI values from cores of the well are statistically related to the irreducible water saturation and porosity values from log data. The resulting equation, similar to the Wyllie and Rose, Tixier, Timur, and Coates equations, relates permeability directly to effective porosity and irreducible water saturation. Unlike these general equations, however, this new equation is specific to the reservoir under investigation because constants are defined for the reservoir. The derived equation can be directly applied to wells or reservoir model grid blocks, where water saturation and porosity are known. This method is more straightforward to use and generates more precise permeability estimates with higher vertical resolution. Several examples demonstrate the accuracy and practical applications of this technique.
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Production Engineering and Geoscience Integration (PEGI) as an Integrated Tool for Reservoir Surveillance and Opportunity Generation for Dukhan Field, Qatar
Authors J.M. Negron, B. Dwiyarkoro, W. Hasan and A. AbuhelaiqaIn an effort to integrate production performance and geological data, Qatar Petroleum developed a tool (PEGI) that assesses the current fluid front movement and reservoir behavior. The tool along with a collaborative review process, assists operation subsurface engineers and geoscientists in their evaluation of the reservoir performance while identifying new opportunities (e.g., by-passed oil) and data requirements. PEGI links structural and stratigraphic reservoir models to production/injection data, well completion history, pressure and logging surveys, within a date, depth and layers database. This linkage provides continuous quality control by simultaneously and iteratively reviewing all data on the same platform in “real-time.” The tool also ties surveillance activities with reservoir characterization and simulation efforts. The process consists of developing mapping units based on geologic layers for interpreting fluid contacts and pressures. The engineering and geoscience data are integrated to guide the reservoir management through improved understanding of the flood front movement and dynamic behavior through time. New development opportunities can be easily visualized and analyzed both in 2D and 3D to better understand reservoir geometry and performance by multidisciplinary teamwork. Potential new well locations and areas of interest are flagged for further investigation. PEGI provides a solid understanding of reservoir geology and fluid dynamic behavior through visualization which supports the well placement process.
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Unlocking Small-Scale GTL: Cost-Effective Platform for Producing Drop-in Fuel From Syngas via a Single-Loop, Catalytic Thermochemical Process
More LessWe describe a new gas-to-liquids technology that converts syngas to high-quality gasoline, diesel, and/or jet fuel through a catalytic thermochemical process that minimizes complexity, improves product quality and increases yield. Syngas-to-gasoline plus (STG+) converts 1 MMBtu of natural gas feed into ~5 US gallons of liquid fuels, enabling the use of cost-effective, small-scale (6,000 bpd) GTL plants. Our data are from laboratory research, pilot and demonstration plant operations, and independent laboratory testing. We also compare the two leading GTL technologies (Fischer-Tropsch and Methanol-to-Gasoline) to the STG+ process. Our results are applicable to the GTL supply chain, development and operation of GTL plants, and end users of syngas-derived drop-in fuels. Because STG+ is cost-effective at scales as small as 400 bpd, it is particularly attractive for stranded or flared gas. From pilot and demonstration plant operations, independent lab testing, university research, Aspen simulation and financial analyses, we show: • The gasoline product has >91 octane, contains <1 ppm sulfur and ~0 benzene, and meets or exceeds other ASTM standards. • It only requires ~$120M to build a 2,000 bpd commercial plant and produces high-quality gasoline at the cost of $65 per barrel crude oil because of its high yield and efficiency. • STG+ is consistently more cost-effective, both in capital and overall costs, than Fischer-Tropsch and even the MTG processes at small, medium and large scales through a series of comprehensive technical and economical analyses. This is the first in-depth presentation of the STG+ process comparing its properties and benefits with the FT and MTG processes.
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A Novel Approach for Characterising Reservoir Properties and Post-Stimulation Effectiveness in Multi-Layer Completions
Authors D.-L. Chang, J.A. Gantt, H. Al-Kharaz and M. BerzouPressure transient tests of wells completed in multi-layer reservoirs have always been and continue to be a challenge for interpretation. Hence, characterizing layer properties from well tests, and determining and monitoring individual layer performance in commingled completions are complex and intensive tasks which could have significant impacts on well and reservoir management. Without accurate assessment of stimulation effectiveness and dynamic skin mechanisms, potential gains in long-term production may never be realized through appropriate action. This paper discusses a hybrid approach for synergizing multi-layer pressure transient analysis with production logging analysis of flow and pressure profiles while accounting for carbonate matrix acidization physics. This approach uses two completely different but complementary tools, which are the existing multi-layer pressure transient analysis option in a pressure transient analysis package and a post-completion inflow performance analysis suite developed by the ExxonMobil Upstream Research Company to analyze carbonate acid stimulation effectiveness for RasGas wells. Based on field experience and acidized wormhole growth physics, RasGas and ExxonMobil jointly developed a new approach to multi-layer characterization using a workflow synergizing pressure transient analysis and inflow performance analysis to analyze post-completion well tests. A field example is described to illustrate the advantages and added value of enhanced understanding of strongly multi-layer producing reservoirs.
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Remaining Oil Saturation Determination in Dukhan Arab C and Arab D Reservoirs
Authors T.A. Wahlheim, W.H. Jamieson, A. Schnacke, J.R. Dixon, T. Attia, L. Barrios, M.N. Ab Majid, H. Silva, A. Trabelsi and M. OmarThe Dukhan Field Arab C and Arab D Jurassic reservoirs have been developed via natural depletion followed by peripheral water injection of variable salinity waters. Additionally, the Arab D crestal development has been influenced by the expansion of the primary gas cap and subsequent gas cycling project. Six wells were recently drilled, cored and logged in areas of the reservoir that had been partially swept by water with the objective to quantify the remaining oil saturation (ROS) at these locations. Data acquisition to determine the oil saturations consisted of coring and acquiring a comprehensive logging suite comprised of resistivity, induction, dipole sonic imager, sonic scanner, electric imager, nuclear-magnetic resonance, and dielectric. The coring utilized low-invasion methods, with deuterium oxide tracer, to assess the degree of invasion. The cores were analyzed for routine properties and by Dean Stark analysis for ROS. Core description was done at a thin section and macroscopic level. Wellbore salinity samples from separate flow units were obtained to characterize the water in the swept zone to assist in evaluation of the water saturation from the logs. Following collection of the data, analysis was performed to: • Integrate the core and log saturation data to develop most likely estimates of ROS. • Examine the impact of throughput using reservoir simulation models. • Assess remaining oil saturation by reservoir, zone, and rock type. • Assess the uncertainty and establish ranking criteria in ROS measurements. ROS from high-quality deep resistivity logs using true formation water salinity data provided the most likely measure of ROS at reservoir conditions. The integrated analysis resulted in a consistent set of ROS measurements grouped by zones and rock types. This dataset can be used for additional studies identifying future opportunities for improved recovery from the reservoirs.
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Application of an Integrated Approach to Preserve Geologic and Seismic Consistency in a History Matching Workflow of a North Sea Chalk Reservoir
Authors H. Sudan, E. Tolstukhin and L. HuReservoir surveillance using 4D seismic has become a valuable resource for managing decisions under uncertainty. This paper highlights an integrated workflow to preserve geological consistency while calibrating a reservoir model using 4D seismic and production data. We demonstrate a successful application of this approach on our North Sea chalk reservoir undergoing waterflood, where a number of repeat seismic surveys have been acquired over time and leveraged as a quantitative source of information for describing the spatial distribution of reservoir properties and compaction. This seismic monitoring data has resulted in the ability to better manage the waterflood by providing fluid movement insights and subsequent improvement of infill well placement. To capture geologic variability and ensure model predictability, geostatistical parameterization techniques using multiple-point statistics are used to represent the uncertainty in the reservoir model. Additionally, the workflow employs a rock physics model to generate a synthetic 4D seismic response from flow simulation. Inconsistencies between the predicted and observed 4D differences are used to classify the reservoir model shortcomings. The uncertain geological parameters are updated in an optimization loop through the minimization of a misfit function comprised of both production and 4D seismic misfit formulations. The closed-loop workflow is managed by an in-house computer-assisted history matching tool using a stochastic optimization algorithm. The integrated approach yields improved reservoir management by encouraging multi-disciplinary collaboration between geological, geomechanical, geophysical and reservoir engineering disciplines.
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Emerging Technologies and the Future of Hydraulic Fracturing Design in Unconventional Gas and Tight Oil
By E. FonsecaAs industry leaders seek solutions to the myriad of challenges facing unconventional projects, research and development efforts continue in the area of multistage fracturing design. These research activities are focused on the identification of novel approaches to hydraulic fracturing (HF) design that can lead to more effective design practices in the future. This paper describes emerging technologies within the building blocks of HF design for multi-stage horizontal wells, and proposes how application of these technologies can lay a foundation for the development and evolution of future industry practices. The industry debate on HF design commonly revolves around a perceived need for more powerful software tools that can capture complex fracture geometries. This perspective or position within the broader industry is due in large part to the cloud of microseismic induced events that is oftentimes observed to envelop a treatment area. Some interpret that these events arise from very complex fracture geometry, and therefore modeling tools with increased specialization are needed. Rather than focusing only on the ability of the software to replicate complex fracture geometries, a higher-level and integrated view of HF design is recommended. As shown in Fig. 1, this integrated approach considers the progressive analysis and application of subsurface diagnostics and modeling capabilities, and how they can influence meaningful decisions in the area of HF design. In reality, the capability for HF design is as strong as the weakest of these three components and need not rely solely on modeling capability. For example, consider the scenario where an advanced set of subsurface diagnostics are found to be limited by software capabilities due to the inability of the software to replicate the diagnosed phenomena with credible physics. This situation limits the use of subsurface diagnostics because the field observations are not mapped to the modeling capabilities and a relevant decision. In a similar scenario, modeling capabilities may be underpinned by credible data and diagnostics, but also lack the ability to influence a critical design parameter such as pump rate, well landing depth or fluid choice. This paper explores how emerging technologies within these building blocks are evolving and how this progress is resulting in new and relevant engineering choices in the design of hydraulic fractures. These choices include design for lateral sweet-spotting, better approaches in sequence and spacing of wells and fractures, and re-fracturing decisions for horizontal wells.
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New Sour Gas Corrosion Inhibitor Compatible with Kinetic Hydrate Inhibitor
Authors C.M. Menendez, J. Jardine, W.Y. Mok, S. Ramachandran, V. Jovancicevic and A. BhattacharyaThe presence of hydrogen sulfide in high pressure gas systems causes several complications. Sour gas corrosion is a major concern in the oil and gas industry due to the presence of localized corrosion. At high pressures and low temperatures hydrates can occur. Sour gas decreases the pressure and increases the temperature at which hydrate formation occurs. Operators have used both corrosion inhibitors and kinetic hydrate inhibitors to decrease the capital requirements of developing sour high pressure gas systems. The development of sour gas corrosion inhibitors that are compatible with kinetic hydrate inhibitors is a major requirement for qualifying corrosion inhibitors for these applications. This paper describes laboratory work on the development of a new corrosion inhibitor by performing various performance and compatibility tests with kinetic hydrate inhibitor. The new corrosion inhibitor needed to meet various additional requirements which made the development process even more complex. The partitioning of a corrosion inhibitor between the oil and water phases has a significant impact on inhibitor selection and treatment strategy. General corrosion performance was addressed using mass loss and electrochemical data. Evaluation of localized attack was performed using vertical scanning interferometry (VSI). The main advantage of this approach is in providing quantitative data for product performance differentiation in the presence of localized corrosion.
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Shifting Reservoir Development Focus to IWAG for a Matured Water Flood Case
Authors S.K. Shrivastava, M.B.A. Rizal, A.N. Cheng Ho, R.B.A. Rasid and M.F. SedaralitThe subject oil reservoir in offshore Sarawak, Malaysia, has oil accumulation in an anticlinal structure, bounded by two growth faults running ENE-WSW direction. It comprises of coarsening upward sequences in the shore face environment. Initial development, purely under depletion using conventional wells, has been associated with rising GOR trend and declining reservoir pressure, raising concerns about depletion strategy. Second phase of development wells has further aggravated the pressure scenario, and water injection has been contemplated as the field development strategy. Strict regulation on gas production has been imposed until commencement of water injection. Starting oil production since 1972 under depletion, over last 40 years adapting to new information and technology the strategy has progressively advanced to reservoir pressure maintenance by water injection, then to horizontal wells, and has now focused more into reservoir heterogeneity and layer wise recovery. The current study further probes the EOR development options focusing on micro displacement of oil. Once the peripheral water injection has been fully operational, oil production rate has steadily been built with horizontal infill wells. Water injection has successfully been able to enhance the reservoir pressure close to its initial value in a span of 5 years. Thereafter, with rise in water production, the reservoir oil production has substantially declined and focus has now been more on understanding reservoir heterogeneity and tracking the oil saturation. Detailed laboratory studies to evaluate gas miscibility options for EOR and to enhance the understanding on rock fluid dynamics and reservoir heterogeneity has been recently completed. A detailed reservoir simulation model identifying different reservoir facies embedded with new saturation height function has been thus built. Detailed investigations have been made using the new dynamic model to evaluate the best development option. The current study further probes the EOR development options focusing on reservoir heterogeneity, layer wise recovery and micro displacement of oil. One dimensional and compositional model has also been used to understand applicability of different Gas EOR processes. Though Miscible CO2 gas injection process gives a higher recovery; after rigorous evaluation, in line with the overall field EOR strategy, iWAG has been identified as the new EOR technology to enhance the field recovery over water injection.
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Development and Testing of Advanced Wireline Conveyance Technology for Rugose Open Hole Conditions
Authors A.F. Ahmadzamri, C.H. Myers, O. Abdelzaher, M. El-Gammal, S. Ahmed and S. RemmertA newly developed style of bottom nose assembly for wireline logging tools is capable of maintaining logging string momentum as the toolstring traverses highly rugose sections of the wellbore. This can reduce or eliminate the need for other conveyance technologies in deviated wells and aid successful descent in horizontal wells. Although current technology has addressed a significant portion of the market, conveyance in rugose open hole still presents a significant challenge. Drillpipe and coiled-tubing conveyance of wireline logging tools has cost and risk considerations, for example logging tool hold-up on ledges in rugose hole can result in costly hole conditioning and re-logging operations. More recent advances in conveyance technology, particularly open hole tractors, have provided additional options for conveying open hole wireline logs. However, rugose hole also presents challenges for open hole tractors including limited opening diameters that result in loss of wall contact, effect of contact forces on rugose formations, and ledges that hold-up logging toolstrings. Starting from a novel physics based modeling approach of the conveyance operation in rugose open hole, and armed with years of logging experience and data, a family of wireline conveyance tools (Fig. 1) were developed and tested to address this challenge. Exhaustive laboratory based testing supported by virtual testing and simulation verified the proposed tool concepts. Intellectual property protection through invention disclosures and filing of patents was then completed. A number of field-worthy prototypes were then developed. Finally several promising field trials were conducted confirming the viability of the developed technology.
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An Assessment of the Influence of Micro-Porosity for Effective Permeability Using Local Flux Analysis on Tomographic Images
Authors S.N. Apourvari and C.H. ArnsCarbonates are typically heterogeneous over multiple length scales. Due to varying connectivity of pore space features at different scales for carbonates, exhibiting bi-modal or multi-modal pore size distributions, the reliability of petrophysical cross-correlations for predicting the transport properties is reduced. The recent emergence of high resolution micro-CT technology in conjunction with robust numerical methods helps to address this problem. Due to the finite resolution of X-ray images current pore scale flow models only consider macro-pores; the pores which are resolved at the image resolution. The importance of micro-pores in fluid flow and solute transport has been proved, although qualitatively, in many applications including hydrocarbon production from carbonate rocks, CO2 storage and subsurface groundwater remediation. In this study we quantify the effect of microporosity on effective permeability for different porous media with exhibiting a varying amount of micro- and macro-porosity. We combine Gaussian random fields (GRF) and particle based models to construct model structures with dual-scale pore types. The Brinkman equation is solved directly on the images to calculate the effective permeability via the lattice Boltzmann method while quantifying the flux through the micro-porous regions. Connectivity analysis conducted on the samples revealed the connectedness of macro-pores through micro-pores. Micro-porosity incorporation increased the connectivity of the macro-pores and consequently the effective permeability of the whole system. This paper introduces a methodology to quantify the effect of microporosity on the fluid flow and incorporate it into the macropores. The approach was first tested on three homogeneous model structures and images of two sandstone rocks, before being implemented on more heterogeneous model structures with bi-modal pore size distribution. The work presented here enables us to couple the effect of sub-resolution pores and macropores in a physically meaningful way. This approach might have important applications to the calculation of permeability for unconventional reservoir rocks.
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Semi-Automatic Facies Up-scaling Technique for Litho-Seismic Classification - Application to a field located in Western Offshore Africa
Authors S. Sengupta, T. Cadoret, F. Pivot and G. FederleA classical objective of reservoir characterization using seismic attributes is to provide a lithology-related attributes that may be used as an aid for interpretation and ultimately as an input for the geological model building. For such an objective, supervised classification techniques take advantage of well data in order to constrain the learning phase of the classification methodology. The output can be pseudo-petrophysical cubes or facies probability cubes. Total has developed an internal tool which enables conversion of inverted seismic attributes (such as acoustic impedance and Poisson’s ratio) into ‘lithocubes’ describing the probability to find some selected lithologies. These lithocubes are seismic attributes and hence have the same resolution as the seismic. In order to achieve proper on supervised classification it is essential to have the facies description compatible in terms of scale with the seismic attributes cubes. This up-scaling can be performed qualitatively without implicit use of the petro-elastic quantitative information such as Vp, Vs and density. Moreover, there could be significant variability in the up-scaling results according to the choices made by the operator performing a manual up-scaling (facies grouping and minimum thickness of each layer corresponding to a given facies for example). This paper describes a semi-automatic workflow capable of limiting the subjective influence of the operator on the final up-scaled well facies. By using quantitative criteria based on the petroelastic behavior of each facies it is possible to help the operator to achieve objective up-scaling choices. Ultimately, this workflow allows to improve the reliability of classified lithocubes.
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Ultrafast Determination of Archie and Indonesia m&n Exponents for Electric Log Interpretation: a Tight Gas Example
More LessIt may take several months to measure the Archie or Indonesia parameters of a tight rock. As a result, a long time elapses between the acquisition of electric logs and their final interpretation. We describe a method that provides reliable measurements of these parameters in one day. The method combines NMR and electrical determinations. The latter are performed using a patented 4-contact cell. A description of method is given and a tight sand case study discussed.
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Estimation of Rock Compressive Strength Using Downhole Weight-on-Bit and Drilling Models
Authors P.B. Kerkar, G. Hareland, E.R. Fonseca and C.J. HackbarthIn unconventional gas and tight oil plays, knowledge of the in situ rock mechanical profiles of the reservoir interval is critical in planning horizontal well trajectories and landing zones, placement of perforation clusters along the lateral, and optimal hydraulic fracture stimulation design. In current practice, vertical pilot holes and/or the laterals are logged after drilling, and the sonic and neutron log results are interpreted along with mechanical rock properties measured in the laboratory on core material. However, coring, logging, and core analyses are expensive and time consuming. In addition, as they are typically only performed in a few wells that are assumed to be representative, there is considerable uncertainty in extrapolating results across wide areas with known variability in stratigraphy, faults, thicknesses, hydrocarbon saturations, etc. This paper reports a method for estimating mechanical rock properties and in situ rock mechanical profiles in every well in a development, based on calibration from initial rock core analyses plus drilling data that is routinely acquired. Wellbore friction analysis was coupled with a torque and drag model to estimate in situ unconfined compressive strength (UCS) and Young’s modulus (YM) profiles. The key process steps include: a) Calculate the weight and wellbore friction force of each element of the drill string from bottom to the surface; b) Adjust the hook load (HL) by subtracting the weight of the hook and entire drill string; c) Iteratively compute the friction coefficient to match calculated and observed HL; d) Estimate downhole weight-on-bit (DWOB) by applying a stand pipe pressure correction to the calculated HL and considering potential sliding and abrasiveness; e) Use a rate of penetration (ROP) model developed for polycrystalline diamond compact (PDC) drill bits considering a force balance between a drill bit geometry and formation and a wear function depending upon the formation abrasiveness and bit hydraulics to compute confined compressive strength (CCS). The resulting CCS was correlated to UCS and YM using regression constants obtained from laboratory triaxial test data on whole core. Using examples from horizontal wells in a siltstone play in Alberta, Canada, this manuscript demonstrates a workflow to estimate rock strength from drilling data. The predicted UCS and YM values were compared with log data and potential uncertainties arising out of drilling data are discussed.
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Two Strategies for Attenuating Internal Multiples in Land Data
Authors M. Retailleau, J. Shorter, H. Farran, T. Wa Hong, N. Benjamin and A. PicaTwo new internal multiple attenuation methodologies are presented. The first approach uses a 3D wave equation based multiple modeling technique followed by 3D adaptive subtraction. The recorded data are back propagated/propagated through a reflectivity model (obtained from a preliminary migration) of the overburden. All possible multiple raypaths are modeled by using different combinations of two sub-windows in this reflectivity model. Each combination results in a specific multiple model. The generated multiple models are then simultaneously adapted and subtracted from the input data. The second approach is a 3D dip extraction and filtering technique, taking advantage of any dip discrimination between the primaries and multiples. It works on post stack and pre stack volumes. We show how the two methods are complementary and how they can be combined. The first approach can be applied to any seismic data plagued with strong internal multiples and is perfectly adapted to modern dense, wide azimuth surveys. The second approach works on any seismic volume in which multiples and primaries have different dips in a given domain. Some real data examples from South Oman 3D seismic datasets are shown. All are characterized by a heavy multiple contamination, generated by strong shallow reflectivity sequences in a flattish overburden, and overlying deeper, weaker and heavily structured primaries. By revealing structures previously invisible, these techniques add a lot of value to existing seismic data sets. The generation mechanism of internal multiples is often quite complex making them difficult to predict. The main benefits of the methods described here are that they work in absence of move out discrimination and without the need of a precise identification of the internal multiple generators.
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Comparison of Probabilistic Techniques in the Study of Fluid Effects on Seismic Properties
Authors W. Ampomah, H.Y. Chen and J. AssadThe parametric method is known for probabilistic estimation of hydrocarbon reserves (Smith et al. 1993). This analytical approach is not “black boxy” as compared to the Monte Carlo simulation. It uses common statistical information. More so, the relative impact of the input parameters is easily ranked to ascertain each individual’s contribution to the total uncertainty. This paper elaborates the use of the parametric approach to analyze the uncertainty associated with the effect of reservoir fluids on seismic properties. The outcome is compared with Monte Carlo simulation and deterministic techniques. A forward modeling algorithm based on fluid substitution procedure is employed in the study. The model assumes each reservoir fluid such as black oil, volatile oil, gas condensate, dry gas and water is saturated in the rock pores. The effect of these fluids on seismic properties such as compressional velocity, shear velocity, acoustic impedances is simulated with uncertainty. Moreover, saturation changes effect on these seismic properties in a two phase system is also studied. Beyond these, a relative impact analysis is carried out to know the individual input data’s contribution to the total uncertainty. Sandstone reservoir rock and fluid properties from laboratory are used for the analysis. Scale-up techniques are used to ensure consistency between laboratory and seismic scale data. The results from both parametric and Monte Carlo simulation showed a good agreement. The results showed a unique effect exhibited by each reservoir fluid on the seismic properties. This approach can assist in identifying reservoir fluids especially at in-situ conditions from the seismic results. The outcome also showed a similar observed result in the Wyllie plot of velocity versus fluid saturation changes. The prediction of saturation effect on seismic properties would enrich time-lapse reservoir monitoring in identifying unswept zones and aid in optimizing in-fill drilling.
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Reservoir Rock Typing of Upper Shu'aiba Limestones, Northwestern Oman
Authors S. Al-Tooqi, N. Al-Habsi, M. Al-Shukaili and S.N. EhrenbergCore samples from 10 wells in Lower Cretaceous limestones of the Upper Shu'aiba Formation were characterized by conventional core analyses, petrography, bulk chemical analyses, and mercury injection capillary pressure data to define reservoir rock types (RRT) for input to reservoir modeling. Initial grouping by lithofacies allows linkage of rock types to a 3D geological model, but results in RRT with high degrees of overlap in petrophysical properties. When diagenesis is included, however, in the form of porosity cut-offs added to the lithofacies criteria, RRT can be defined having both 3D geological significance and distinct ranges of pore-throat size distribution. The use of total porosity as a rock typing criterion is based on the interpretation that porosity is controlled on reservoir scale by depositional clay content of the local stratigraphic environment. The seaward and uppermost parts of the clinoforms have low clay and thus highest porosity. Although most of the pore space is microporosity, higher total porosity corresponds with higher proportions of macropores and probably also with greater frequency of open fractures, resulting in better permeability. High-porosity samples also have several systematic positive differences in MICP characteristics from lower-porosity samples of the same lithofacies. Because both lithofacies and porosity are related to the sedimentological and stratigraphic organization of the Upper Shu'aiba clinoforms, the RRT defined by these criteria can potentially be implemented in a reservoir model for assigning particular ranges of petrophysical properties to distinct portions of each clinoform. By this procedure, seven RRT have been defined in the present selection of samples.
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A New Treatment Technique of Produced Water from Polymer Flooding
Authors X. Wang, R. Liu, Z. Shao, J.H. Miller, S. Wakasiki and R. LisanaAfter the water flooding process or secondary oil extraction, the tertiary oil extraction has been widely used in Chinese oilfield in recent years. Although this technology can enhance the oil recovery by up to 12%, it also produces more and more polymer-flooding wastewater as byproduct per year. Without proper treatment, the oil pollutant pollutes and poisons the water and atmospheric environment. Removing polymer and oil from the oilfield produced water is an important aspect of pollution control in oil and gas industry of China. One of the major technical requirements of the crude oil exploitation industry is to minimize the concentration of hydrolyzed polyacrylamide (HPAM), crude oil and suspended solid (SS) in the oilfield polymer-flooding wastewater and realize the reuse of this wastewater. In this study, the membrane technology was used to achieve this goal in laboratory-scale dead-end test unit with flat polyvinylidene fluoride (PVDF) membrane (MW 100 kDa). We systematically inspected the membrane fouling mechanism, the variety of total membrane resistance, total fouling resistance, the dominant resistance, membrane fouling driving force and the filtration proceeds in the filtration process. The orthogonal method and multivariate linear regression method were applied to analyze the influencing degree of the main pollutant concentration on the critical flux. According to comparison of the average rates of change of the critical flux for the HPAM concentration, oil concentration and SS concentration in single solute solution, double solute solution and oilfield polymer-flooding wastewater, HPAM can decrease the average rate of change of the critical flux for other two solutes and has the crucial effect on the critical flux. According to this research, the ultrafiltration membrane technique can be efficiently used to treat synthetic oilfield polymer-flooding wastewater. A standard procedure is developed to be a methodology reference for the wastewater treatment.
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Chemical Consolidation of Sand Propped Fractures in a Chalk Reservoir Offshore Denmark With Enzymatic Calcium Carbonate Scale
Authors M.L. Morkved, C. Knight, B. Bhagwan, A.G. Algora, W. Zhuang, H.C. Rohde and A.C. NelsonSand and proppant production pose a safety risk due to erosion, fill of wells and facilities, often resulting in significant deferred production. A number of wells in the Danish offshore sector are currently closed in or beaned back due to proppant production from sand propped fractured wells where proppant is back produced to surface facilities which were not designed with sand handling capability. A new sand consolidation treatment involving enzymatic calcium carbonate scale has been applied to individual zones downhole to remediate failed proppant fractures. The technology is an environmentally friendly alternative to commonly used resins and has the added benefit of being completely reversible. A detailed coiled tubing program was successfully executed in a harsh offshore environment with numerous challenges including identification of sanding zones, chemical contamination, logistics, and selective downhole placement. Laboratory testing was undertaken where unconsolidated proppant was treated with the consolidation chemicals. These results provided important input for defining the placement strategy and indicated that results could be replicated in the field. Successful results have been achieved from this industry first application of enzymatic calcium carbonate scale to consolidate sand propped fractures in a chalk reservoir. The field application supports the laboratory results, where sand free production of over 700 BOPD has been restored in a well previously closed due to proppant production with limited impact on well productivity. A post-job monitoring program has been designed to further evaluate this technology. The development of enzymatic calcium carbonate scale consolidation has led to a method for chemical consolidation of proppant fractures that is more environmentally friendly than alternative methods, is reversible and has limited impact on well productivity.
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Lattice Boltzmann Flow Simulations With Applications of Reduced Order Modeling Techniques
Authors L.L. Brown, J. Li, V.M. Calo, M. Ghommem and Y. EfendievWith the recent interest in shale gas, an understanding of the flow mechanisms at the pore scale and beyond is necessary, which has attracted a lot of interest from both industry and academia. One of the suggested algorithms to help understand flow in such reservoirs is the Lattice Boltzmann Method (LBM). The primary advantage of LBM is its ability to approximate complicated geometries with simple algorithmic modificatoins. In this work, we use LBM to simulate the flow in a porous medium. More specifically, we use LBM to simulate a Brinkman type flow. The Brinkman law allows us to integrate fast free-flow and slow-flow porous regions. However, due to the many scales involved and complex heterogeneities of the rock microstructure, the simulation times can be long, even with the speed advantage of using an explicit time stepping method. The problem is two-fold, the computational grid must be able to resolve all scales and the calculation requires a steady state solution implying a large number of timesteps. To help reduce the computational complexity and total simulation times, we use model reduction techniques to reduce the dimension of the system. In this approach, we are able to describe the dynamics of the flow by using a lower dimensional subspace. In this work, we utilize the Proper Orthogonal Decomposition (POD) technique, to compute the dominant modes of the flow and project the solution onto them (a lower dimensional subspace) to arrive at an approximation of the full system at a lowered computational cost. We present a few proof-of-concept examples of the flow field and the corresponding reduced model flow field.
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Production Monitoring by Intelligent Chemical Inflow Tracers in Long Horizontal Heavy Oil Wells for the Nikaitchuq Field, Northern Alaska
Authors M.D. Kuck, L. Nofziger, P. Gentil and E.S. FaevelenObtaining reliable production surveillance data is not always achievable with all completion types. Two heavy oil production wells in the Nikaitchuq field in Northern Alaska hosted such challenges. The wells do not flow naturally and ESP’s were chosen as the artificial lift (AL) method, thus eliminating the option of applying conventional flow profiling techniques such as production logging tools (PLT). Permanent chemical intelligent tracer systems were installed to monitor inflow distribution and water breakthrough along the long horizontal production intervals. The nature of heavy oil fields in this area require long, horizontal production wells with adjacent injectors to drive waterflood support. Lateral production conformance in this area was unknown or could not be definitively confirmed. A means to understand inflow performance along laterals in order determine appropriate lateral length and optimize waterflood design was needed. Early water breakthrough due to uneven water front and possible matrix bypass has previously been experienced in nearby, analogous fields. A means to determine the general location of water breakthrough was also desired. Oil and water intelligent tracers were chosen to provide the required information to enhance pressure management and waterflood techniques. These intelligent tracers were placed strategically along the lateral in multiple development production wells. With this knowledge in hand, other production optimization tools such as ICD’s, DTS and zonal isolation packers can be assessed to help effectively manage the waterflood. The intelligent tracer systems are designed to release unique tracer chemicals when exposed to the corresponding target fluid, i.e. oil and water contact triggers intelligent oil and water tracer release respectively. The tracer transient signatures are interpreted to assess the type, location, and quantity of fluid flow along the lateral. Re-start monitoring campaigns have been conducted for three wells during dry oil production. The data interpretation confirmed toe production in two of the wells. Quantitative estimates of inflow distribution along the producing sections were made for all wells.
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Dynamic Multiphase Kick Tolerance Allows Safe Drilling Which Led to Huge Gas Discovery in a HPHT Exploration Well in Malaysia
Authors L. Umar, Y.Y. Thiam, M.S.B.A. Murad, W.K. Woo, S. Nas, B. Escalano and A. EkaTTD-1 well is located in offshore block SK in East Malaysia and this High Pressure High Temperature (HPHT) well proved to be a challenging well to drill with a pore pressure ramp exceeding 15psi/ft and a bottom hole pressure exceeding 14,000psi. Due to the predicted steep pressure ramp and the resulting narrow margin between the pore and fracture pressures advanced dynamic kick simulations and Managed Pressure Drilling (MPD) was used to drill TTD1 well. This paper details the importance of dynamic kick tolerance calculations in getting the well to the targeted drilling depth. In order to optimize casing setting depths in a narrow margin HPHT drilling environment, dynamic flow checks and dynamic formation integrity tests using managed pressure drilling technology were used to define the lower and upper boundaries. The dynamic well control simulations take an influx followed by standard well control procedure of shutting down the pumps and closing the BOP before circulating out the influx. The kick tolerance of a well is governed by fracture pressures, influx volumes and kick intensity. The kick tolerance limits are defined by the operator and if the limits are reached the next casing has to be installed before drilling can proceed. In addition to the dynamic kick tolerance analysis conducted in the planning phase, a simplified version of the software was installed on the rig. Drilling supervisors and well control specialists were trained to operate the software. The purpose of the rigsite kick simulator was to enable the drilling supervisors to quickly determine if an influx could be circulated out safely without exceeding surface or downhole pressure limits during a well control situation. The simplicity coupled with realistic multiphase technology permits simulations to be performed as soon as an influx is taken. The multiphase dynamic kick model is able to simulate a well control event more realistically when compared to the common single bubble kick calculations. These more realistic calculations allowed drilling to proceed whilst maintaining pre-determined kick tolerance volumes. This allowed the deeper targets to be achieved in the TTD-1 well.
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TOTAL E&P Consideration of new Technologies in Rotating Machines to Respond to the Requirements of Future O&G Developments
More LessTo respond to ever more demanding and critical requirements dictated by the current and future developments of O&G fields, combined with harsher environmental conditions, TOTAL consider that innovation and introduction of new technologies are today unavoidable, and this is particularly true for rotating machines. Some examples to illustrate this tendency can be listed, such as: • Reinjection pressures in the reservoir ever increasing, reaching 700 bar and more, • Gas flows increasing and thus requiring more and more power, • Ever increasing water depth: Today, it is almost ordinary to install multiphase pumps and soon high boost multiphase pumps and compressors at minus 1,500 meters of water depth and soon deeper, • Less complex compression shaft lines (high speed motors, oil free, Active Magnetic Bearings, sealless), no HC emissions, for upstream applications, • Remote Monitoring and Diagnosis, • Harsher environment conditions (Artic, large ambient temperature range, offshore, corrosive contaminants, salts, sand, harmattan, etc.), isolated production sites, • Wet gas with CO2 and H2S with selection of appropriate metallurgy, • More viscous fluids to be pumped in multiphase conditions from the sea bed, • Very large gas turbines for future all electric FPSOs and floating production facilities (LNG). And of course all these new technologies are developed with the requirement of limiting CO2 and NOx emissions, increasing energy efficiency, and improving equipment reliability, while preserving safety of the people and the machines. The famous “two machines two years” criterion which uses to be the golden rule in the past among most of the Majors is no longer applicable and thus superseded as conditions of new O&G developments, whether climatic, environmental, reservoirs, technological, are changing very rapidly. Therefore, TOTAL, have implemented a thorough qualification process to introduce innovations, allowing thus to lead the required technological evolution, to cope with the rapid market changes, to be able to respond to more and more complex projects, to be ready to implement these new technologies whenever required, reducing costs and increasing energy efficiency, while minimizing the associated risks. The paper provides some examples of implementation of such new technologies in rotating equipment and describes the qualification process that is followed to declare these technologies fit for purpose.
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Parametric Study on Completion Design in Shale Reservoirs Based on Fracturing-to-Production Simulations
Authors C.-E. Cohen, S. Kamat, T. Itibrout, H. Onda, X. Weng and O. KresseAdvances in horizontal drilling and new practices in hydraulic fracturing have changed the paradigm of shale reservoirs in the last decade. Nevertheless, completion and stimulation engineers still face serious challenges due to the complex physics involved during hydraulic fracture propagation including hydraulic fracture interaction with natural fractures, stress shadow effects, and proppant transport in complex fracture networks. One of the main questions is how to optimize the number of stages and the placement of perforation clusters accounting for these complex physical phenomena and the wells’ economics. To answer this question, it is necessary to analyze how the completion design and the fracturing process are related to the short and long term production. This paper investigates the relation between the production and the completion design. A state-of the–art, fracturing-to-production simulation workflow is used to carry out a parametric study on completion design. The fracturing simulations are performed with the unconventional fracture model (UFM) that models the hydraulic fracturing process in a complex formations with pre-existing natural fractures including interaction with natural fractures and between hydraulic fracture branches (stress shadow effects). The resulting complex fracture networks are then explicitly gridded to build an unstructured grid that is then passed to a numerical reservoir simulator to run the production simulations and accurately model multiphase reservoir flow around complex hydraulic fracture networks. The base case of this study represents a synthetic reservoir model replicating properties of the Marcellus shale. One of the main parameters investigated is the number of perforation clusters per stage for both a constant pumping rate and for a constant average rate per perforation cluster. We also investigated the influence of the number of stages on production, for a given lateral length and a given total treatment volume. The results from this study provide new understanding of the impact of completion design on production and illustrate its use to find optimum completion design based on modeling. For example, some results show that for a constant average rate per cluster a clear optimum can be found as function of the number of cluster per stage, while this task can be more challenging with a constant total pumping rate.
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Post-Production Heavy Oil Operations: A Case for Partial Upgrading
Authors T. Lokhandwala and M. BarrufetThis paper investigates the economic viability of post-production partial upgrading, specifically visbreaking, of heavy oil. We evaluate the potential technical and economic advantages and disadvantages of using visbreaking as a tool for reducing diluent use. Additionally, we identify the cost and energy drivers affecting the economic performance of this partial upgrading operation through a probabilistic Net Present Value (NPV) analysis. We have created a screening tool that can be used for a preliminary evaluation of visbreaking for transportation of heavy-oil solvent systems. Partial upgrading at the wellsite can potentially reduce operational costs to producers and transportation companies. A comparative economic study offered by this test can be used to make decisions on whether to proceed to a more detailed investigation of the process. Importantly, we have created a first-pass standardization tool for the screening of heavy oils for partial upgrading. Visbreaking can prove to be an economically favorable addition or, perhaps, even an alternative to blending heavy oil prior to pipeline transportation. In fact, operational costs of visbreaking are offset by the reduced cost of diluent and capital expenditures that can be mitigated within a reasonable time frame. Finally, we conclude that the altered fluid properties of a visbroken product require less energy per barrel for transportation, which translates to a more attractive economic scenario for transportation for the two baseline cases presented.
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A Comprehensive Approach of Well Integrity Surveillance
Authors M.N. Al Khamis, F. Al Khalewi, M. Al Hanabi, K. Al Yateem, A. Al Qatari and H. Al MuailuThe well integrity surveillance program is a mechanism applied to oil, gas and water production/injection wells to ensure the sound quality and healthiness of all their completion components. Currently, there are differences in the well integrity surveillance programs applied by field operators worldwide due to the differences in the causes of well integrity issues that are faced in every field or geographical location. Recognizing such differences, Saudi Aramco formed a Well Integrity Surveillance Guidelines and Best Practices (WISG&BP) team to review and establish a comprehensive well integrity surveillance program that can be applied corporate wide for all well types (oil, water and gas). The developed program not only ensures the identification of well problems at its infancy but also maintains the healthiness and upkeep of Saudi Aramco asset. This surveillance program focuses on the following six primary well integrity surveys: 1) Wellhead valves integrity inspection and greasing. 2) Surface and Subsurface Safety Valves (SSV & SSSV) and Emergency Shut-Down (ESD) System functionality and integrity testing. 3) Annuli survey. 4) Landing base inspection. 5) Temperature survey. 6) Corrosion logging. An application has been developed to streamline and automate the planning, scheduling, execution, data validation and data posting process to ensure compliance with these best practices. This application provides tracking capability of the surveillance program and initiates alert, notification and escalation to the responsible entity at every stage of the surveillance process. The wells with identified integrity issues are flagged on a Well Watch List and closely monitored until their issue is resolved. This surveillance program is reviewed and updated every 2 years to reflect the advancements in surveillance technologies and capture any necessary modifications based on arising field observations. This paper summarizes the well integrity surveillance program applied in Saudi Aramco. It provides a workflow of the well surveillance process and describes the automation application used to capture and track the program implementation. The comprehensive strategy provided in this paper can be used as guidelines for maintaining the well integrity of all well types worldwide.
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Multiphase Drag Reducing Agents to Increase GOSP Production in Offshore Saudi Aramco: Field Applications
Authors N. Al-Amri, R. Al-Khaldi, H.B. Al-Qahtani and M. Al-AmoudiDrag reducing agents (DRA) are commonly used in the industry to increase pipelines’ throughput by reducing the frictional pressure drop along the pipeline segment. The application of DRA has been primarily for single phase flow; however, a multiphase DRA was introduced and trial tested in an offshore gas-oil separation plant (GOSP) in Saudi Arabia to maximize the production of heavy oil from the GOSP without the need to flare the excess produced gas. This initiative was considered to avoid a major GOSP upgrade. The objective of conducting the trial test is to determine the effectiveness of the DRA in maximizing GOSP fluid output utilizing the existing equipment and layout without having to go into flaring mode. To achieve this, a multiphase DRA was injected into the GOSP discharge line or trunkline to reduce pump discharge pressure by lowering line differential pressure. This DRA was tested twice on the same facility with contradicting outcomes from each test mainly due to the different procedures used. Analysis of the inconsistency in the different test results sheds some light on the optimum environment of the multiphase DRA and on the best practices to be followed in a test procedure. This paper provides results and analysis of both DRA trial tests along with detailed procedures of each test. It elaborates on the causal factors of the discrepancies noticed, and the optimum environment for the multiphase DRA application.
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Derisking Prerosetta Prospects In The Nile Delta Through Depth Imaging
Authors M. Andreolli, N. Bienati, E. Gentile, M. Manera and A. TansiniThe explorative targets of the proposed case history are the Cretaceous sequences in a ENE-WSW fold related to the “Syrian Arc” event, and the overlying Oligocene to Miocene sequences that pertain to the Nile Delta System. The structural pattern is sealed by the evaporites associated with the Messinian Salinity Crisis. When facing such complexity the integration between interpreters and geophysicists is the key point in order to obtain a reliable imaging and hence a reliable geological model. Moreover, an integrated working platform is required to speedup the process that requires strong team interaction and a certain number of iterations to achieve the desired degree of confidence. The workflow started from the estimation of the velocity in the post-Rosetta where a global grid tomographic approach was used. Then for the Rosetta we initially assumed a tentative uniform velocity that resulted in some push-down and pull-up effects. Such effects were removed after geophysical and geological evidences provided information about the real geometries of Rosetta, allowing to tune velocity variations within salt. In the deepest part, the velocity analysis was even more complex because of the limited offset/depth (6000m/8000m) ratio. A modeling exercise gave confidence on the effective illumination of the deeper reflectors and a large scale grid tomography was performed. The final velocities in the pre-Rosetta showed two significant velocity inversions validated by geological models and analogues. The proposed workflow led to significant improvements of the imaging of pre Rosetta sequences, both in terms of SNR and geological reliability of the prospect structure with a consequent de-risking of the prospects.
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Online Inspection & Clamping of Large Size Steam Headers (52”& 48”) to Mitigate Steam Leaks from Multiple Weld Seams in Utilities Piping Systems
More LessThe scope of this paper is to discuss the background, design challenges, online damage assessment, repair selection and sustainment efforts undertaken to mitigate large scale caustic stress corrosion cracks in the common low pressure steam system. Caustic ingression in the steam system through contaminated boiler feed water used for de-superheating caused multiple cracks in the steam piping systems. Crack locations were predominantly visible at the longitudinal and circumferential weld joints of the common utilities steam header. Cracks were observed on the intrados and extrados of elbow joints, tee joints and straight pipe sections of the large size (52” and 48”) header. Cracks were also observed downstream of significant capacity de-super heaters and upstream of steam users in the process units. The common steam system is utilised for process heating, pump and compressor drivers. Unplanned shutdown of the common steam header system for repair or replacement would require a multiple mega train outage and majour business impact. Crack propagating beyond critical length will lead to catastrophic failure of the steam system. Online solutions needed to be (1) safe to install, (2) designed for sustainment for over 2 years until a permanent repair could be affected, and (3) not impose any risk of further damage during installation.
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Mauddud Fractured Reservoir Analysis, Greater Burgan field: Integrated Fracture Characterization using Static and Dynamic Data
Authors O. Alzankawi, R. Al-Houti, E. Ma, F. Ali, M. Alessandroni and M. AlvisThe understanding of the flowing behavior coming from Mauddud carbonate reservoir in Greater Burgan field has always been a matter of debate. This reservoir is composed of tight complex carbonates with net gross pay that ranges from 10 up to 25 feet. Its porosity response is generally low, as well as its matrix permeability. The best strategy for reservoir exploitation it is for sure by mean of horizontal drilling but results did not match expectative, since some unsuccessful wells were drilled. For aforementioned reasons it is crucial to understand and characterize the presence of fractures in the Mauddud carbonate reservoir as well as the presence of vugs and leached features in order to establish if the observed production is related to matrix or to the fracture network contribution. The understanding of the relationship between matrix characteristics, fracture distribution, and well production will allow planning a better developing strategy for the sweet spots. This paper describes initially the results of geological fracture characterization, and then presents the integration of such results with available dynamic data. Main results obtained from geological characterization are that fractures are mainly faultrelated, limited in height by the carbonate reservoir, and sometimes oil bearing even if no oil stains were found in matrix. The study of dynamic data, combined with the geological results, was mainly dedicated to recognize the well flowing regimes that cannot be associated only to matrix contribution, but that are probably due to a flowing from fractures. Obtained results could lead to better diagnostic and better development strategies in this challenging reservoir.
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Implementation of Real Time Geosteering to optimize horizontal drilling
Authors A. Al-Zuabi, H. Bahman, O. Al Zankawi, R. Kotecha, B. Mereno, P. Mukherjee, A. Muddvakat, S. Al-Sabea and J. Al-HumoudWith increasing complexity to tap oil in clastic reservoirs due to stratigraphy, structure and facies variation optimization of placement of horizontal well has become a key to success. To augment this aspect Kuwait Oil Company (KOC) has established Geosteering Centre which has become the hub for decision making while the well is getting drilled for landing at top of reservoir or lateral is being drilled. The Great Burgan field located in South East Kuwait asset of KOC major Horizontal drilling campaign started in 2005 mostly in clastic reservoirs.. This field been on the production since 70 years, most of its development wells were drilled and completed as vertical or deviated. It was decided to utilize horizontal well technology to drill thin productive layers. This paper illustrates an integrated approach using 3D-Model along with seismic analysis, knowledge sharing and most advanced Geosteering technology to successfully transfer, edit, and interpret the dynamic data in real time to monitor the drilling progress specially the lateral section. This state-of-the-art computing and visualization technology enables geologists to take corrective measures keeping the well in sweet zone as much as possible, through direct satellite communication with the rig’s Geosterring unit and planned well course VS actual trajectory was continually updated and well path corrected based on information received. The Geosteer center moved Field Development South-East Kuwait to a whole new level of collaboration that is equipped with latest in visualization, communication and computer technology in order to properly place and geologically navigate one of the world’s largest siliciclastic reservoirs. Today the interactive process of geosteering, using real-time data and making real-time decision has resulted in mitigating inherent geological risk in order to optimize the best drilling results for each horizontal well and to ensure an effective implementation of all new ongoing field development plans and made it possible to tackle thin reservoirs which now can be drilled economically.
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Application of Artificial Neural Networks for Well Logs
More LessNeural Networks are a powerful tool - • For computation when the data available is less than adequate. • Can solve fundamental problems such as formation permeability prediction from the well log response with high accuracy. • Have great potential for computing results from historical data which would otherwise be irrelevant for analysis. Neural Networks find various applications in the Petroleum industry - Optimize the hydraulic fracture design, Permeability Predictions, Facies classification etc. This study deals with the development of a neural network for predicting well log response. This network is trained by input-output pairs of known well log data, using which an estimation model is created. This estimation model can then compute permeability output for input well log data of different offset wells. The neural network created uses a feed forward model with a Levenberg-Marquardt learning algorithm. Error is calculated using Mean Squared Error (MSE) technique. An optimum number of neurons in input, output and hidden layers were set. The network was trained with given pair of input response of well log dataset and its output permeability response was predicted. The study also considers two different cases to mark the importance of optimized training of a neural network before it can be used for predicting permeability values in offset wells. This technique is completely data driven and does not require priori assumptions regarding functional forms for correlating permeability and well logs (Sharma et al. 2011). The network developed in this study gives highly accurate results. Also it is very flexible as the training algorithm, number of layers and other parameters can be changed according to the data set available. It proves to be cost effective and saves time since it does not require core analysis. Neural Networks prove to be a useful emerging alternate tool to conventional methods.
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Uncertainty Quantification of Forecasted Oil Recovery using Dynamic Model Ranking with Application to a ME Carbonate Reservoir
Authors A.P. Singh, M. Maučec, G.A. Carvajal, S. Mirzadeh, S.P. Knabe, A.K. Al-Jasmi and I.H. El DinHistory matching, being an ill-posed optimization problem, attempts to render multiple realizations of reservoir models that satisfy a given objective function with applicable constraints. A variety of assisted history-matching (AHM) techniques is currently being developed and used with the main objective to generate statistically diverse ensembles of history-matched models to capture the uncertainty in the distribution of reservoir parameters. This paper targets the outstanding questions of how to a) rigorously quantify the uncertainty in the distribution of the most prominent reservoir parameters that govern the reservoir connectivity and b) rank the history-matched models and identify the model candidates for production forecasting without compromising the notion of uncertainty. A workflow has been developed that integrates the modules for AHM and dynamic model ranking (DMR) based on forecasted oil recovery factors (ORFs). A pattern recognition methodology based on a kernel k-means clustering algorithm is used to identify key reservoir models. The reduced set of models is used to minimize the computational load for forecast-based analysis, while retaining the knowledge of the uncertainty in the recovery factor. The comprehensive probabilistic AHM and DMR workflow was implemented at the operator’s North Kuwait Integrated Digital Oilfield (KwIDF) collaboration center. It delivers an optimized reservoir model for waterflood management and automatically updates the model quarterly with geological, production, and completion information.
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Ceramic Screens - An Innovative Downhole Sand Control Solution for Old and Challenging Cased Hole Completions
Authors A. Nadeem, M. Lopez, S. Joly, R. Jackson, A. Strazzi and S. WildhackErosion in gas wells caused by sand producing formations can result in severe operational issues leading to the degradation of surface and downhole equipment and the shutdown of production facilities at surface. Old cased hole wells in highly unconsolidated, poorly sorted sandstone formations require robust sand control. In such instances, conventional gravel packing methods are not always possible and the installation and maintenance of downhole sand control throughout the well life can be challenging. In gas wells where sand velocities are high, the supporting metallic material being used in, for example standalone sand control screens is subject to plugging and subsequent rapid wear because of its low resistance to erosion. Hence the longevity of metallic sand control equipment is poor and frequent expensive recompletions and workovers are required. An innovative solution using ceramic screens was used in an existing gas well in Bolivia, South America. The well geometry included double casing with sub-optimal cement across the target zone and, due to the complexity of voids behind the casing, it was not possible to perform the initial option of a cased-hole gravel pack. In addition to sand control the completion required mechanical zonal isolation to prevent water ingress at a later stage. In summary the project involved removing the existing completion, isolating deeper lying depleted producing zones, clearing the casing of debris, reperforating the casing, installing a new completion with ceramic screens and zonal isolation valves. BG Group in conjunction with German ceramics manufacturer ESK developed over a period of 18 months a series of ceramic sand control screens and sliding sleeve protections that provided a downhole sand control completion solution complete with mechanical water isolation. The successful project exceeded all expectations and to date the well has produced sand free. The operational time and recompletion costs were less than of a cased-hole gravel pack, the operation much simpler and safer. BG are now working on a project to use this innovative technology as a thru-tubing sand control solution for existing high rate gas wells offshore worldwide where open hole or cased hole gravel packs have failed.
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Dynamic 3D Imaging of Fluid Mobility in Natural Fractures Using High-resolution Positron Emission Tomography
Authors M. Maučec, R. Dusterhoft, R. Rickman, R. Gibson, A. Buffler, M. Stankiewicz and M. van HeerdenPositron emission tomography (PET) continues to have wide-ranging medical application and is based on the detection of gamma radiation emitted from the decay of certain types of radionuclides. Modern PET scanners produce three-dimensional (3D) images of the radiation source, in discrete time steps, using tomography analysis. This paper presents an application of PET for studying fluid mobility in pressurized low-permeability rocks in the presence of natural fractures. This technique uses a high-resolution PET scanner and image reconstruction based on filtered back-projection. Traditional techniques have been limited to pressure measurement of fracture conductivity and effective permeability, but little is understood about the dynamic flow and velocity profiles within the fracture. The objective of this work was to investigate if it is possible to measure the dynamic (e.g., time-lapse and continuous) distribution of the fluid flow as a function of the overburden stress. PET imaging was applied to the flow of a brine solution, which was tagged with 18F-fluorodeoxyglucose (FDG) positron emitting radionuclide, through nonfractured sandstone and naturally fractured shale cores. A special composite container was manufactured to sustain high-pressure conditions and minimize the absorption of emitted gamma rays. The experimental apparatus is described, and it is demonstrated that the 3D images obtained with a grid resolution of 2 × 2 × 2 mm3 allow clear determination of the fluid flow rate through the core as a function of overburden pressure and time. PET images are direct observations of the radiation source and allow an unambiguous determination of the fluid distribution in the core. The results of this research can be used to validate the numerical modeling of fluid flow through fractured rock matrices, to enable more accurate estimates on the directionality of fractures from the fluid distribution as a function of time, and to obtain more quantitatively sound estimates of fracture connectivity.
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Treatment of Produced Water from Unconventional Resources by Membrane Distillation
Authors J. Minier-Matar, A. Hussain, A. Janson and S. AdhamUnconventional resources (Shale gas/oil) use significant volumes of water for hydraulic fracturing (fracking). While some of the water used is fresh groundwater, there are more environmental pressures to use brackish water sources for fracking. This brackish water may need to be treated to lower the saturation levels and to allow mixing of field chemicals. Unconventional resources also produced high volume of flow-back water (produced water). This produced water (PW) contains high levels of total dissolved solids (TDS) and desalination may be needed to allow recycling or reuse of this water source. Membrane Distillation (MD) is an innovative process that can desalinate highly saline waters (30,000–100,000 mg/L TDS) more effectively than reverse osmosis. As a proof of concept, bench-scale MD testing were performed on brackish and produced water samples (30,000 mg/L-60,000 mg/L TDS) obtained from Texas. Results have shown excellent TDS rejection (99.9 %) on all the water samples that were tested without impacting membrane’s flux performance. To evaluate the O&M and scale up issues, two one m3/day MD pilot units are currently operating side by side at a local desalination plant in Doha. Brine from the thermal desalination plant was used as representative high salinity water (70,000 mg/L), similar salinity levels could be found in brackish groundwater and/or flow-back water. It was assumed that all other contaminants that could cause membrane fouling (such as suspended oil, solids, organics, microorganisms) will be removed in a pretreatment step prior to MD. Preliminary results showed that the pilot units were successful in completely removing salt. Flux was very stable for more than 2 weeks. However, it was concluded that pretreatment is critical for stable performance of the MD units. This presentation will provide up to date data on MD bench and pilot-scale performance with O&M issues and projected cost estimates.
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History Matching the Clean-up of a Well at the Oselvar Field Using a Transient Multiphase Flow Simulator
Authors B. Solvang, M.K. Krogstad, D. Lysne, A. Ashrafian and E.A. QualeThis paper presents the history matching of a clean-up operation of a long horizontal oil well at the Oselvar field in the North Sea using a commercial multiphase flow simulator. Data recorded during the actual clean-up is presented in the paper, and is compared with simulation results. Well clean-up is the process of flowing the drilling and completion fluids out of a new well, removing formation damage and filling the well with formation fluids. The role of upfront simulation of well clean-up is to optimize the operation and provide the basis for the operational procedure to be used onsite. Also, after the well clean-up has been carried out, the simulation tool may be used for history matching in order to gain understanding of what happened during the operation and assess the quality of the upfront simulation model. The data from the Oselvar clean-up operation revealed that the liquid flow rates at the initial choke size were significantly different from the rates predicted by the upfront simulations. Also, the time it took until no more drilling mud arrived topside was longer than expected. The data shows that the heel of the well was producing for several hours before there was any production from the toe of the well. This is attributed to the high initial productivity of the heel of the well, and to unexpected rheological behavior of the drilling mud. Constructing a transient downhole boundary condition based on the recorded data and on interpretation of petrophysical well data, a history matched simulation model was built that gave good agreement with the data. The work in this paper contributes to improved understanding of mud retention in wells during clean-up operations. The data and simulation results demonstrate why the modeling approach widely used in the industry may lead to a conservative estimate of the pressure margin before a well is killed, and an optimistic estimate of the time that is required to clean the well.
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Integration of Downhole Fluid Analysis and Advanced Mud Gas Logging Reduces Uncertainty in Reservoir Evaluation
More LessReservoir fluid characterization is crucial for the success of field exploration and development phases. Early detection of hydrocarbon allows accurate determination of reservoir fluid properties and plays a key role in reducing uncertainty in reservoir evaluation and future field development strategies. Advanced Mud Gas logging (AMG) system and wireline downhole fluid analysis are among the important means available in the oil and gas industry for such analyses. Each method has its limitations and advantages, therefore developing an integrated approach and workflow that combine these two different methods are important for the success of fluid sampling and for better reservoir characterization. The aim of this integration work is to improve reservoir fluid evaluation during the entire well starting from the early stage of drilling. This can be done by having reliable early hydrocarbon detection from mud logging which allows optimizing formation PVT sampling program, and helps to develop correlations for the benefit of fluid evaluation in future wells. This work presents a successful integration of mud logging and downhole formation fluid analysis for better reservoir fluid characterization in an offshore Malaysia field. Advanced Mud Gas logging was run to provide early formation fluid evaluation, which was utilized to design and optimize formation fluid sampling, PVT lab work and further DST requirement. By using AMG, it was possible to identify the significant changes observed on fluid composition (C1-C5, C6-C8 range) and also to distinguish potentially fine variations within the possibly same fluid type. Based on these results detailed fluid evaluations and sampling points were suggested. In addition several potential hydrocarbon/water contacts were identified. Wireline formation tester (WFT) was also run for downhole fluid identification (DFA) and to acquire representative fluid samples in addition to reservoir pressure and fluid mobility. This paper also presents strategies used for fluid analysis and sampling to provide accurate fluid characterization in a challenging environment. The methodology, workflow, analysis, and applications of this field study are presented in this work.
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A Horizontal Drilling Breakthrough in Developing 1.5-m Thick Tight Gas Reservoir—Case Study in Risk Uncertainty Management, Ordos Basin, North China
Authors H.M. Pranata, W. Su, B. Huang, J. Li, P. Wu, N. Wang, Y. Yang, G. Yi, I. Rukachev, O. Azwar and P.M. HalomoanDual-lateral horizontal wells have been the strategy applied in Changbei field to maximize economic development of a tight gas sandstone reservoir. A motor and measurement-while-drilling (MWD) bottomhole assembly (BHA) is normally used to drill 2-km dual-lateral wells within the quartz arenite (QA) sand reservoir that has an average thickness of 15 m. After completing most of the drilling in the thicker axial region of the channel belt, the field development has now shifted toward the channel margin boundary that has more straigraphic complexity and much thinner reservoir. A pilot hole, drilled to provide better understanding of the reservoir thickness near the channel boundary, has revealed that the reservoir was about only 1.5 m in thickness. The application of motor and MWD BHA would have not been adequate to drill and place the well within the very thin reservoir. Therefore, the combination of RSS and the high-resolution resistivity image LWD BHA were applied to replace the motor and MWD BHA. This paper features the successful approach taken using an integrated application of RSS, optimized bit, high-resolution resistivity image LWD, and dip determination well placement technique to overcome the subsurface challenges and to improve the drilling efficiency. RSS and LWD technologies were deployed to provide real-time, full-bore, high-resolution resistivity and gamma ray images to evaluate the structural dips, image stratigraphic events, and provide better trajectory control with near-bit survey capability. The field real-time data will be discussed. This integrated application has helped to place the well optimally along the thin target reservoir, thus optimizing the reserve recovery despite the large discrepancy of actual reservoir profiles relative to the original predrill model. The authors also share the successful approach, best practices, and valuable lessons learned that have provided the breakthrough in developing the tight gas reservoir under such complex geological uncertainties and in a very hard, abrasive formation.
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RFEC PIG Designed for Long Distance Inspection
Authors A.A. Mazraeh, F.B. Ismail and A.F. Alta’eeThis paper presents an innovative approach for the design and development of Pipeline Inspection Gauge (PIG) which can inspect pipes from 26” up to 50” with a simple change of shirts using the latest technologies such as Electromagnetic Acoustic Transducer (EMAT) sensors as well as Remote Field Eddy Current (RFEC) sensors for oil pipes inspection, through the creation of a simulation tool capable of generating simulated images from pipeline using Inertial Navigation System (INS) for highest accuracy and precision inspection to protect the environment and equipment from any unexpected accident. There are several dynamo motors utilized to regenerate green efficient power from the flow of the medium inside the pipeline to elongate the distance of investigation by the mean of reduction of the number of individual pigging processes to save time and cost for companies. The INS uses accelerometers and gyroscopes of the type “Integrated Micro Electro-Mechanical Systems” (iMEMS), with these it can be carried out the mapping corresponding to the inspected pipes. Water hammer effect is another factor which has been considered during designing this pig. To avoid suck case to occur the design has been revised and several arms has been devised around the robot to maintain the speed and position of pig all the way through the pipeline.
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Maximizing the Benefits of Real-Time LWD Data for Production Performance Prediction
Authors R.E. Okoroafor, S. Haq, L. Ortenzi, W. Zhou, A. Nkanga, I. Khattak and D. OkenwaAn integrated and innovative methodology for predicting production performance with real-time logging-while-drilling (LWD) data was applied in a single-well analysis. It involved building a geologic and petrophysical model, upscaling it into a numerical simulation model, and then using this dynamic model for production forecast. The case study is a horizontal well that traversed a sequence of interbedded sands and clay beds. This well was placed in a thin oil rim identified in a pilot hole. LWD was the preferred logging method due to high well deviation. The bottomhole assembly consisted of an LWD integrated platform providing triple combo, capture spectroscopy, sigma, nuclear magnetic resonance, and formation-pressure-while drilling data. The integration of the LWD geology, petrophysical, and reservoir interpretation in real time, combined with pressure/volume/temperature (PVT) data from an offset well, provided a good representation of the reservoir. This dynamic model was then used to predict well performance. The estimate suggested a low productivity index (PI), in line with the qualitative estimate from LWD data review. The oil-in-place results from the single-well model were compared with the results of the full field model and found to be in close agreement. Also, the results of the simulation were compared with a productivity test, and production rates were within a 20% range. This study shows that a representative well productivity model can be derived from properly integrated LWD data. This innovative methodology demonstrates a quick way to build static and dynamic models for wells and use them for production forecasting and other engineering decisions. Since the predictive model can be built while drilling, its estimates can aid well construction decisions (e.g., length of drain, need to sidetrack) and optimize completion strategy. The innovative methodology can be applied in highly deviated wells, extended reach wells, and other well architectures to provide real-time productivity estimates for completion decisions.
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Open-Hole Fluid Displacement for Carbonate Stimulation in Liner Completions
Authors C.S.J. Mayer, R. Sau and C.E. ShuchartToday, many wells in heterogeneous carbonate reservoirs throughout the Middle East and Caspian Sea area are being completed with long intervals and complex completion equipment, such as limited entry liners and inflow control devices (ICDs). Accurate modeling and understanding of fluid placement during a stimulation operation through such long complex completions can be quite challenging. In this paper, an integrated approach of modeling, experiments and computational fluid dynamics (CFD) simulations will be presented. A computational tool based on a transient one-dimensional (1D) approach has been developed in-house to model stimulation through such completions. In order to validate the 1D approach for reliable fluid displacement predictions, annulus fluid displacement experiments in perforated liners supported by CFD simulations have been conducted. The experimental setup consists of an outer Lucite pipe representing the well-bore geometry and an inner aluminum pipe with multiple perforations of variable diameter. The setup mimics the real field application in a 1:1 scale with respect to the pipe and perforation diameters while the test section is limited to 27 ft. The experimental procedure is as follows: (i) fluid is pumped into the annulus through the perforations until the annulus is completely filled, (ii) the fluid tank is switched “on-the-fly” to the tank with the displacing fluid resulting in the displacement of the annulus fluid by the displacing fluid through the perforations. The experiments and the CFD simulations indicate that even with a single open perforation inside the 27-ft test section, the three-dimensional (3D) flow field around the perforation rapidly transitions to uniform annular flow within a few feet uniformly displacing the annulus fluid. The model also provides insight into various well injection processes in sandstone and carbonate formation, such as scale squeezes, solvent treatments, and HF acid treatments.
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An Investigation of Diagenesis Related to the Top Surface of the Upper Shu'aiba Formation in Cores from Northwestern Oman
Authors S.N. Ehrenberg, S. Al-Tooqi, M. Al-Shukaili and N.R. Al HabsiCore and log data from Lower Cretaceous limestones of the Upper Shu'aiba (US) Member in northwestern Oman were examined for evidence of diagenesis related to the top surface where this reservoir is overlain by shale of the Nahr Umr Formation. Cores from six vertical wells in three oilfields were studied by profiles of conventional core analyses, petrographic observations, and bulk-rock geochemical analyses. Neither bulk-carbonate stable-isotope analyses nor bulk-rock strontium concentrations show trends indicative of upward-increasing meteoric diagenesis below the top-US surface. Porosity and permeability data also show neither increasing nor decreasing vertical trends suggestive of surface-related diagenesis. Meteoric leaching and cementation may nevertheless be pervasive throughout the US reservoirs, at least partially accounting for extensive aragonite dissolution and filling of the resulting macropores with coarse calcite cement. Three of the cores show trends of upwards-increasing bulk-rock iron, manganese, phosphorous, and uranium. These effects are attributed to sea-floor authigenesis driven by reducing conditions within the upper several meters of sediment following each cycle of US sedimentation. In addition, the top 7 m of limestone in one of the cores contains several percent late saddle dolomite, and minor saddle dolomite also occurs near the tops of several other cores. Mg for dolomitization can have been provided from diagenesis of clay in the Nahr Umr Formation. The results of this study thus indicate both early sea-floor mineralization and late dolomitization in some places below the top-US surface, but do not confirm locally more intense meteoric diagenesis underlying this surface.
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Mitigating Hydrates in Subsea Oil Flowlines: Consider Production Flow Monitoring and Control
Authors A. Kanu, N. Al-Hajri, Y. Messaoud and N. OnoRisk of gas hydrates occurring in subsea flowlines presents serious problems to offshore oil and gas production operations. Hydrate incidents can occur in oil and gas production systems provided that the favourable compositional mix and thermodynamic conditions exist. The principal method used to mitigate hydrates in subsea flowlines is the injection of hydrate inhibitor chemicals. Thermodynamic hydrate inhibitors (THIs) have traditionally been used but these have disadvantages, namely high OPEX with increasing chemical volume demand, space constraints, high CAPEX, and safety and toxicity concerns. Recently, low dosage hydrate inhibitors (LDHIs) such as kinetic hydrate inhibitors (KHIs) and antiagglomerants (AAs) which offer advantages of minimal volume and space requirements have received considerable attention. However, widespread application of these new classes of inhibitors has been limited by yet a number of concerns including water-cut and/or subcooling temperature range limits, lack of predictive models, toxicity, biodegradability, compatibility, and produced water quality and disposal issues. This paper presents a case study of an alternative “do-nothing” operational technique involving the comingle flow of well streams from different reservoirs at a pre-determined volume flow ratio, with temperature monitoring. Effective well-stream volume flow ratio was determined by predictive model studies of fliud systems hydrate equilibrium and pipeline operating envelops, followed by field trials. Results show that risk of hydrates in flowlines with multi reservoir fluids can be minimised by the control of the in-line fluid compositional mix by conventional flow control operation. Conceptual assessment studies suggest that this method of hydrate control could provide a cost-effective alternative to the use of chemical inhibitors, on a short-medium term basis, particularly in cases of seasonal hydrates and minimum-facility marginal oil production. Further study of effect of salinity of the produced crude on hydrate formation, given anticipated water-cut breakthrough with time, would further confirm the economics of this strategy on a field lifecycle basis.
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Assessing Reservoir Fracture Potential over Kra Al-Maru, Riksah Structure in the Kuwait Gotnia Sub-basin
Authors R. Srigiriraju, A. Heyam, T.F. Al Adwani, N. Banik, B. Chakrabarti, A.A. Ghneej, M. Alaa, A. Amer and A. Jaradatotation of structure, which contributed to the evolution of the Kra Al-Maru structure and the orthogonally oriented Riksah structure as indicated by our study. The structural analysis indicates that all major open fractures align NNE-SSW. The Riksah structure is a well defined four-way-closure anticline; however, the prospectivity is dictated by fracture potential of the reservoir. The evaluation of the fracture potential of the reservoir is best served by the azimuthally (AVOAz) processed 3D seismic data integrated with well observations. However, in the absence of AVOAz data, the study is supported by integration of well observations and key seismic attributes. The seismic attributes are, edge detection/enhanced seismic attributes, combined with prestack seismic inversion attributes like the Poisson’s ratio which is governed by established relationships at wells.
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CNG Application in Qatar
By A.H. KafoodNatural gas has been considered as the most promising alternative fuel for its cleanliness and abundance. It has been widely replacing other conventional fuel in industrial applications as well as transportation. Nowadays, more than14.8 million vehicles are running on Compressed Natural Gas (CNG) globally, and the number is rapidly increasing due to increase of air pollution awareness and financial advantages. There are numerous anticipated benefits of using CNG in transportation instead of conventional fuels in Qatar. In addition to its economic benefits, CNG will significantly reduce greenhouse gas emissions, which will consequently improve air quality in Qatar. Qatar Petroleum is currently evaluating the logistical, technical, environmental and economic viability of utilizing CNG in a wide spectrum of transportation facilities in Qatar and free up equivalent quantities of gasoline and diesel for export. The study covers different aspects such as the distribution network, CNG supply points, modifications and supporting facilities required to convert gasoline and diesel vehicles to CNG. CNG pilot project has been initiated in Qatar on November 2011 to address the full chain of CNG application in transportation; the pilot project will address the filling stations risk assessment, operational procedures, vehicles’ maintenance and associated issues. This paper will present the challenges and problems that might be encountered in the deployment of full scale CNG system in the State of Qatar and the way forward.
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From a Project-Oriented to an Operations-Focused Organization – The case of QG OPCO Well Engineering and Intervention Division
By T.J. PaezQatargas (QG) OPCO experienced an impressive growth in the last 6 years, starting with QG2 in 2006, and followed by QG 3&4, QG1 first in-fill drilling campaign, and finally QG1 second in-fill drilling campaign in 2012. These projects helped QG OPCO become the biggest LNG producer in the world. The sudden expansion did not allow the Well Engineering and Intervention (WEI) Division to easily assimilate the changes. Even though WEI grew in size (i.e. number of personnel) by recruiting global talent, this accelerated growth demanded a different approach to develop organizational capabilities (resources and processes) to operate the new well count. In 2012, WEI embarked on multiple initiatives to transition from a Project-oriented to an Operations-focused organization. The first initiative was related to the need for one overarching Well Integrity Management System since different criteria and procedures were utilized in each of the ventures. The second initiative addressed the need for a Well Control and Blowout Prevention Manual and Contingency Plan to prevent and mitigate well control situations in scenarios where Jack Up availability and Drilling organizations were limited (drilling organizations set up to expand QG OPCO were reallocated, downsized or dismantled). In addition, a new WEI structure was required in order to gain efficiencies, align personnel with business needs, and sustain or develop capabilities in the workforce. This paper discussed the journey of WEI in pursuing organizational capabilities in order to meet ever-demanding global energy challenges and QG OPCO vision – to be the world’s premier LNG Company.
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Challenges in Uninterrupted Production and Supply of Gas to Mega LNG Trains
By N. DeyThe paper will highlight key production and operational challenges with complexity in feeding natural gas to mega LNG trains. The unique feature of Qatar’s LNG project is the integrated energy value chain, starting from offshore gas reservoir and wells then all the way to liquefaction, transportation terminal and delivery to international customers. The natural gas starts its journey from giant North Field reservoir; is produced through huge mono-bore wells, flow continues via subsea wet gas pipelines to onshore where it is separated into condensate, water and feed to the world’s largest LNG trains. The major ventures Qatargas2 and Qatargas3&Qatargas4 operate gas wells, completed in Khuff reservoir, spread over several wellhead platforms, transport gas through multiple multiphase wet gas pipelines to four mega LNG trains at onshore. The planning strategy for start from right amount of gas extraction with right composition while achieving uniform draw down at reservoir level continues until controlling gas volume from each well complying with facility design limit, within operating boundaries from flow assurance point etc. Time delay from offshore to onshore through pipeline transfers, must be considered on volume and composition estimation of gas. Several activities on wells, wellheads, subsea pipelines add further complexity to the process. As gas is becoming the energy of choice for the world community, sharing knowledge and experience of producing and continuous gas delivering to maintain the critical supply chain will add value to the hydrocarbon industry. The paper is focused on the complexity of factors, challenges of planning and executing supply along with several other factors to this element of big energy supply chain. Multiple boundaries, affecting gas movement need to be respected, monitored and achieved. The responsibility lies in having complete knowledge of all factors, ability and experience to steer through the complex set up; fail proof procedures supported by world class execution style.
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Late Oligocene-Early Miocene Basin-Center Evaporites in Relationships to Multi-Stage Tectonic Inversions in the Sinjar Trough, NW Iraq and NE Syria
Authors P.C. Tai, G.J. Grabowski, C. Liu, J. Kendall and A.O. WilsonThe Sinjar Trough is a major east-west trending extensional feature in Northwest Iraq and Northeast Syria. It began to develop in the Late Cretaceous (the Maastrichtian) due to transtensional tectonics and was inverted during the late Pliocene- Pleistocene as a result of the Zagros Orogeny. Through biostratigraphic, Sr-isotope age dating, petrographic, and sequencestratigraphic studies of two late Oligocene-earliest Miocene basin-center evaporite intervals in Northwest Iraq and adjacent Northeast Syria, we recognized several minor episodes of inversion in the Sinjar Trough during the Paleogene. The Basal Serikagni Anhydrite (BSA) is a thin basinal anhydrite unit imbedded between the middle and late Chattian deepmarine carbonate sequences. The BSA extends into Northeast Syria but is missing in several adjacent wells within the Sinjar Trough. The Dhiban Formation is a thicker late Aquitanian-early Burdigalian evaporite-dominated interval mixed with carbonates. It overlies the Serikagni Formation and onlaps onto the carbonate ramp margins of the Euphrates Formation, which prograded towards basin center from the northeast and southwest. In Northeast Syria, the same basin-center evaporite is called the Dibbane Formation and shows local thickening and thinning. The overlying Jeribe Formation, however, has a uniform thickness across Iraq and Northeast Syria. The areal distribution, facies, and stratal geometry of these basin-center evaporite-bearing intervals reflect the antecedent topography during their deposition. Minor inversions within the Sinjar Trough before or during the late Oligocene caused non-deposition or erosion of the BSA in Northeast Syria. Another episode of inversion before the early Miocene created lowrelief highs and differential accommodation within the Sinjar Trough. The Dhiban/Dibbane Formation simply filled the remnant basin and was able to cover the highs during the lowstand stage, resulting in local variations of the basin-center evaporite accumulation. This study may shed some light on the timing of early trap formation within the Sinjar Trough.
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