bluuebunny/crossref_metadata_2025_split huggingface dataset:
Real-Time Data Gathering and Transmission of Fracture Treatment Operations and Micro Seismic Monitoring to Enable Optimization of Field Development
Authors: Al-Khudiri Musab M. , AlSanie Faisal S. , Bartko Kirk M. , Kurdi Mohammed S , Kashif Muhammad , Meraj Hamood 
Published: October 2015

Abstract
This paper highlights the tremendous impact of real-time data transmission and visualization on hydraulic fracturing, also known as "fracing." Here, we will focus on tight reservoirs. Utilizing the advanced real-time visualization system with high-resolution data transmission enables the frac engineers to achieve promising results, and ensures effective decision making and data substantiation from real-time fracing centers at their base offices.
Saudi Aramco adopted single-viewer visualization solutions to support a wide range of different operations with a single system through which Aramco users can simultaneously monitor various activities, including drilling and post-drilling activities with ease. This solution was approved to support the high supremacy of hydraulic fracking operation and their requirements by attaining the high speed of data transmission and visualization at the rate of minimum one-second data. The data transmitted all the way from the rig site to the base monitoring centers and displayed on customizable templates to meet the requirements of the data visualization with real-time calculations.
The importance of real-time monitoring micro-seismic data is the key tool to determine the frequency of hydraulic fracturing during frac operations. This type of operation needs to be verified with the simulation models, and the whole range of complex operations is made possible with the advance technique to transmit real-time data. This real-time data was used for monitoring and treating wells at the most required rate of data availability at the base where complete optimization teams utilize different simulation applications to connect direct real-time data feeds, which are used to capitalize on the industry-standard well data transmission protocol (WITSML).
An Innovative Cement Formula to Mitigate Gas Migration Problems in Deep Gas Wells: Lab Studies and Field Cases
Authors: Al-Yami Abdullah S. 
Published: October 2015

AbstractGas Migration through cement columns has been an industry challenge for many years. To control gas migration, high cement densities are required to successfully cement the high pressure formation. Formation gas/influx can migrate through the cement column resulting in gas being present at the surface.Current high density cement formulations do not provide good gas migration prevention due to settling and increase in permeability. To solve the settling problem and reduce permeability of cement, intensive lab work was conducted earlier by Al-Yami et al. (2009).The objective was to develop novel cement formula containing a combination of solids with different particle size distribution to minimize cement porosity and prevent solids settling. Compared to conventional high density cement weighted up with hematite, the developed cement showed no signs of settling, better fluid loss control and improved resistance against gas migration in the lab.Saudi ARAMCO has successfully trial tested their new developed cement formula (Gas Preventing Cement) in 5 wells in 2015 for 9 5/8" casings across high pressure formation to mitigate 9 5/8" X 13 3/8" Annular leaks. This is an effort to help in minimizing gas shut-in potential and safety risks due to casing-casing leaks. The new formula was applied with good cement returns to surface and good wellbore isolation according to the conducted well flowing test. In addition, loggings were run to ensure good bonding of cement. More high pressure gas wells will be cemented using this formulation.
Prediction of Multistage Fracturing Performance in Horizontal Heavy Oil Carbonate Reservoir
Authors: Al-Mutairi Saleh H. , Al-Aruri Ahmad D. , Al-Otaibi Saud F. , Al-Subaie Abdullah M. , Park Han-Young 
Published: October 2015

Abstract
Horizontal oil and gas wells with low permeability might not be economic without multistage fracturing. Nevertheless, heavy oil horizontal wells instigate the additional problems of low mobility and low oil gravity. In these heavy oil prospects, multistage fracturing can increase the reservoir contact tremendously but the viscous nature of oil flowing within the matrix and through fractures may pose a challenge to the economical success of the fracturing treatments. The objective of this paper is to study multistage fracturing performance in heavy oil horizontal wells across carbonate reservoirs.
A sector model was extracted from a full field reservoir model and was then equipped with Local Grid Refinement (LGR) mesh to accurately predict the performance of multiple transverse fractures. The model was used to study the effect of several design parameters on the performance of the horizontal well. Special consideration was given to PVT data. The output of the refined simulation sector LGR model was compared with available analytical and numerical models for multistage fracturing performance predication. Finally, the resulting optimal fracturing strategy was evaluated using the full field simulation model.
This work presents an analysis and history match of actual multistage acid fracturing treatment in heavy oil field. Results of the model were important for the heavy oil field development and well placement and completion strategies.
Optimizing Production & Operation through Automated Well & Network Modeling
Authors: Das Mriganga , Naharuddin Zadil Hayat , Al-Khalid Dhuha 
Published: October 2015

Abstract
Raudhatain field located in North Kuwait produces hydrocarbons from over 230 wells into Gathering Center X with varying complex geometries, completions and downhole equipment. NK asset team is executing a project of modeling the entire NK production system starting with wells in Raudhatain field producing to GC-X, involving building models for the wells and the gathering surface network of flow lines.
There are numerous challenges that the NK asset team is facing in meeting production targets, including controlling water/gas breakthrough in horizontal wells. Mitigation measures include installation of inflow control devices (ICDs). Since inception a decade ago this proven technology has long been used in many oilfields around the world and is increasingly being installed in horizontal wells in Kuwait. To date there are several horizontal wells in Raudhatain field completed with ICDs.
Reservoir modeling and simulation approach is frequently used in the industry capturing the behavior of existing ICD wells. This approach uses conventional modeling tools that are typically more intricate and require expert skills in capturing the dynamic behavior of the wellbore and the reservoir which is less appealing to the operations and practicing engineers.
Limited with time and resources in this project, the NK team took a relatively simpler and fast approach in modeling existing ICD wells in Raudhatain field with the aim of enabling the engineers to capture the behaviour of the wells using existing production engineering tools at their disposal.
The approach can be summarized as follows: ➢Establishing the well performance➢Modeling the individual ICD sections in accordance to the approximate flow distribution/geometry along the horizontal well➢Matching the well with well test data
Key benefits of this approach are: ➢Enabling the engineers to quickly model the ICD wells.➢Facilitated the use of existing tools to deliver engineering models fit for use in the production system.➢Serves the purpose of high level modeling of complex ICD wells and in the future this exercise will certainly be undertaken to capture wellbore hydraulic effects.➢ICD well models are timely added into the gathering network which would otherwise have been delayed using a conventional method.
Produced Water Injection - The Challenges Faced
Authors: Bhola N , Ariaratnam G , Roth N 
Published: October 2015

Abstract
In this paper we will discuss the factors that influence the strategy for produced water treatment and disposal. Various aspects of the produced water treatment plant will have an impact on the water quality achieved, for example operational parameters such as interface levels, differential pressure ratios, flowrates, pressures, temperatures, etc. The required specification for either discharge or reinjection is a key factor in determining the necessary process equipment and chemicals that are needed for the separation process. For injection, the water quality needed to be achieved are often more stringent as it has limitations on solids loadings and particle size as well as oil concentrations.
In this paper we will review a detailed case study that was conducted offshore in the UK North Sea. This site was struggling to achieve the water quality needed for reinjection. The work conducted quantified the key areas that were causing the process problems and explored options such as optimising existing separation equipment as well as maximising chemical efficiency.
The case study will highlight how the overall process performance was improved once the oily water separation challenges faced were identified and understood. Improved water quality was achieved by enhancing the chemical dose rates for one chemical and eliminating the use of another chemical as well as optimising several operating parameters for different parts of the treatment process. The overall work led to reduced operation costs and reduced production time whilst ultimately achieving water quality within the required specification without affecting the export oil quality.
Planning for Uncertainties in Gas Composition: Reduce Project Risks by Early Adoption of a Robust Gas Processing Concept
Authors: Demmers Anton , Gupta Neha , Vaart Rick van 
Published: October 2015

Abstract
This paper demonstrates that selecting a gas processing concept that is robust against changes in predicted gas composition during the maturation of (associated) gas projects reduces the risk of schedule delays and cost creep while potentially presenting opportunities to deliver first hydrocarbons to customers earlier.
During early project phases, the availability and quality of data on the specific field to be developed are usually limited. Consequently, project teams have often been left with two options when designing gas processing facilities. The first option is to rely on old data, data from well tests of questionable quality and/or data from analogue fields, if available, in order to form the basis of their design. This brings relatively high risk of having to redesign once higher quality data become available. Design alterations may delay the schedule to first oil/gas and lead to increased costs and erosion of the overall project value.
The second option is to wait for new well test data to become available before starting work on the gas processing facilities. This approach, though preferable, can result in costly schedule delays and does not guarantee the delivery of accurate data on which to predict the gas composition and base the gas processing design.
Appreciating this uncertainty is the first step in mitigating the risk. The second step is selecting a gas processing concept that is robust against flow and compositional deviations. In this way, the design of the gas processing facilities can go ahead at a low risk before full appraisal of the field is complete. This may enable parallel project phasing by starting the engineering procurement and construction (EPC) phase for the gas processing facilities during field appraisal.
Shell believes that an effective gas processing line-up of an acid gas removal unit (AGRU) that utilises the Shell Sulfinol-X all-in-one amine technology along with a selective acid gas enrichment unit (AGEU) combined with sulphur recovery units (SRU) and sulphur dioxide (SO2) tail gas treatment provides the robustness to deal with high compositional uncertainty for the gas.
The novelty in this paper is recognising that robust gas treating line-ups such as the one described above can have operational advantages and enable developers to secure their licence to operate by meeting emission restrictions. These line-ups can also have additional project execution/schedule advantages that add value to a project.
Specifically, this paper will demonstrate that the small additional capital expenditure required for the proposed robust design is more than compensated for by the acceleration of the project resulting in an overall improvement to the net present value. Additional benefits to the project will be ease of operation, simplicity and ultra-low emissions.
Coexistence of Gas-Condensate and Volatile Oil at Pressure Higher than Saturation Pressure. Physical Explanation and Modeling Approaches. Case Study: Sabriyah Field in North Kuwait Jurassic Asset
Authors: Fava Guido , Descubes Elena , Daoud Ahmed , Sharifzadeh-Najafi Ahmad , Al-Enezi Bashayer , Al-Arouj Mutlaq , Dashti Qasem 
Published: October 2015

Abstract
Sabriyah and Raudhatain are the main fields producing from the Middle Marrat Jurassic formation in North Kuwait with approximately 5 km distance between the two fields. Raudhatain fluid is considered as Volatile Oil, while Sabriyah is described as Gas-condensate. 16 PVT samples from Raudhatain were analyzed and described as Volatile oil. 12 PVT samples taken from Sabriyah field where 7 samples show gas condensate behavior and rest shows volatile oil.
A key challenge in understanding the Sabriyah fluid characterization is the fact that 5 well samples that showed Volatile oil behavior are not separated from the Gas condensate wells by any apparent barrier. In addition, the initial reservoir pressure is much higher than the saturation pressure, preventing the equilibrium of those fluids.
The objectives for this study are to analyze the physical explanation of coexistent of oil and gas-Condensate in one communicated reservoir with reservoir pressure higher than saturation pressure, apply different modeling approaches to accurately describe the fluid behavior in Sabriyah field and finally capture the influence of uncertainty in the type of fluid on the production forecast.
The physical explanation for this phenomenon was investigated from different points of view: the variation of temperature, compositional variation with depth, existence of geological barriers, and facies changes. It was found that the compositional variation with depth and the change of fluids with changes of facies can provide reasonable explanation for this phenomenon. The first explanation related to compositional variations with depth is supported by the observed data that shows a strong relationship between depth and fluid type, while the temperature did not influence significantly the gas-oil phase change. The second explanation related to the concept of gas and oil charge depending on facies is supported by mercury injection capillary pressure data taken from different depth in the reservoirs, this concept improves the understanding of fluid distribution which could not be explained in previous approaches.
This paper shows the way of modeling this phenomena based on these two explanations, which honor both static and dynamic data with special reference to the effect of these different modeling approaches on the production forecast of Sabriyah field.
The near critical fluids which are the type of fluids in Sabriyah field are usually problematic to handle with Equation of State; therefore solving this particular case is expected to add technical value to reservoirs of the same type of fluids.
The facies dependence of gas and oil distribution and the way of modeling this phenomenon is an innovative view that can contribute to the description of similar fields.
An Effective Small Scale Pressure Maintenance Scheme - Conception to Implementation - A Case Study
Authors: Badusha Syed Ibrahim , Mahato Anil , De Santanu , Safar Ahmad 
Published: October 2015

Abstract
Reservoir Depletion is addressed in many ways across the globe with water injection being the most common method. A typical full field water injection scheme takes years for implementation, with surface players like injection facility construction dominating the project cycle and delays are not uncommon. The resulting loss in deferred production and recovery along with continuous amendments to production profiles of the field can be minimized by resorting to DumpFlooding as an easy and quick alternate.
"A" field is a satellite field of Kuwait. Bulk of production is from the thin estuarine channel sand of average thickness of 13ft within Zubair Formation. This channel system is laterally continuous as interpreted from the Isopach map and has a fairly uniform pressure throughout the field. With no aquifer support, a decrease in pressure from the initial levels of 2500 psi by around 1000 psi was observed. The production performance also deteriorated since the operational teams had difficulty keeping the ESPs on operation continuously. The size and location of the field could not economically justify a conventional water injection project. As the reservoir pressure came perilously close to the bubble point, a partial pressure maintenance scheme was conceptualized, with DumpFlooding as injection mechanism.
A systematic plan to address all the uncertainties that could have an impact on the success of the project was listed and addressed. The injection volumes and injection patterns were evaluated and firmed up by a simulation study. Various source water reservoirs were identified and water compatibility analysis was carried out to confirm the suitable injection water. Multiple single well pilots with completions from different source water reservoirs were tested. The productivity & injectivity indices of the different sources and the sink were ascertained. When the full field implementation was carried out, the team was able to take further steps with considerable confidence, having taken important lessons from each stage.
The concept proved to be successful with real benefits seen on the ground. The layer saw a gradual rise in reservoir pressure monitored by an intensive surveillance programme. A rise in pump intake pressure of ESPs ranging between 150 to 200 psi within a span of 1 year was noticed. The field started experiencing trouble free ESP operation. New horizontal producers drilled as a part of the scheme resulted in significant oil gain. A 25% increase in overall layer production was observed. The paper discusses the key milestones from conception to implementation with emphasis on the role played by each stage in the grand scheme of things. A case is thus made for considering DumpFlooding as a necessary intermediary in any upcoming water injection project.
Tracer applications in Water flooded reservoirs in North Kuwait
Authors: Tasneem Al-Twaitan , Chetri Hom 
Published: October 2015

Abstract
SabiriyahMauddud is a giant carbonate reservoir in North Kuwait, under active water flood using 18 inverted 9-spot patterns and 11 peripheral injectors. Water flooding operations require proper understanding of the connectivity between the injectors & producers so that the assurance on water flood sweep is properly diagnosed and corrective actions are initiated. The objective of the paper is to share the planning, sampling & integrated analysis of the tracer applications to enhance the water flood efficiency in a pattern(P- 1) in SabiriyahMauddud at the Crestal part surrounded by four nearby patterns (P-2; P-3; P-4 & P-5) & intersected with numerous faults.
Extensive data illustrating the reservoir connectivity was pre-analyzed in an integrated manner. The data covered permeability trends; openhole logs; RFT data; mapping of high perm streaks; pressure response as time-lapsed static Bottom hole pressure surveys; PVT data; oil rate & water cut trends since the start of water flood activities in 2000. Also, the salinity contrast was used to understand the water movement pathways, as low salinity sea water was injected in a purely depletion drive segment, with no mobile formation water. The diagnostics, however, could not be fully conclusive as the surrounding producers of P-1 were also receiving injection support from P-2; P-3; P-4 & P-5 (surrounding patterns). Distinctive Chemical tracers were injected into P-1 as well as surrounding P-2; P-3; P-4 & P-5, with a comprehensive sampling program at all associated producers. Continuing with sampling & tracking over a period of 2 years has helped to understand the high speed zones and inter-pattern connectivity.
Injectors of Pattern-1 were found to be in excellent connectivity with the surrounding producers, with partial support from the injectors for P-2; P-3; P-4 & P-5. The information helped to scale down the injection allowable for the injector of P-1, resulting in average reduction in water cut from 50-60% to 30-45%. Further optimization is planned in future by isolating the high perm layer from the surrounding producers during rig over jobs and even by horizontal sidetrack of producers for upper part and injectors for lower part (which is high perm zone).
Tracer information, thus, added value to the understanding of the water flood connectivity which has been duly integrated into reservoir models during history match. Also, as the way forward, the strategy has been expanded to all other patterns & even horizontal injectors and is under implementation.
Value was added to the water flood surveillance activities in North Kuwait by proving this way of diagnosing the connectivity in a challenging & heterogeneous reservoir under active water flood.