bluuebunny/crossref_metadata_2025_split huggingface dataset:
Rapid Producibility Evaluation of Thin, Sand-shale Laminated Reservoir - A Case Study in South China Sea
Authors: Guo Shusheng , Cai Jun , Li HuiGeng , Xian ChengGang , Song Ju 
Published: September 2011

Abstract
Laminated sand-shale reservoir poses many challenges in formation evaluation and hence risks on decision making such as oil testing or completions, particularly for offshore. This paper presents a new approach of NMR based rock typing, permeability characterization and rapid production prediction for thin sand-shale laminated reservoir, conducted in an offshore field of South China Sea. The method is validated through a study integrating logs, formation tester and drill string test (DST) data, to build a generally applicable approach. It was used for rapid producibility evaluation right after openhole logging, in order to facilitate the decision making of the consequent completion and production test. Based on a quick yet reliable answer, operators can decide whether the well should be completed and where should be tested in order to achieve the lowest cost and HSE impact and better time efficiency for exploration and appraisal.
The major challenges facing are: highly laminated sand/shale sequences, strong heterogeneities, complex porosity-permeability relationships, and different scales of different measurements. We set up an improved method using NMR measurements to evaluate effective properties within a depth frame of thin beds in order to overcome the resolution challenge because the individual lamination thickness is about centimeters or even thinner, which is much below the resolution of logs. Comparing with DST results, the accuracy of predicted producibility is in an acceptable range, giving great confidence of the reliability in the study result. This case study has demonstrated the applicability of the new NMR based method, and set up a rapid producibility evaluation approach for thin, sand-shale laminated reservoir; and this new NMR method and the approach applied are not limited to this specific field but applicable to other fields with similar geological settings and formation types in this region.
Compositional Modeling of Heterogeneous Anisotropic Naturally Fractured Reservoirs using Control Volume Mixed Finite-Element Technique
Authors: Alnahdi O. , Kazemi H. 
Published: September 2011

Abstract
Compositional modeling of heterogeneous anisotropic naturally fractured oil reservoirs is a crucial issue when assessing the benefits of miscible and immiscible gas injection. This is especially true in large Middle East carbonate reservoirs. This paper presents an efficient methodology to model such reservoirs using a control-volume mixed finite-element technique (CVMFE). The formulation takes into account (1) the full permeability tensor without any compromise and (2) the local interaction of gravity, capillary and viscous forces between fracture and matrix.
We give a clear account of the mathematical formulation so that the readers can utilize the method for writing their own computer code. The formulation pertains to a multi-component three-phase flow system using the dual-porosity model where capillary and gravity forces are accounted for, both on the local and global scales. The local scale is related to the fracture-matrix interaction, while the global scale represents the inter-well flow and flow migration across the field. The compositional formulation used (i.e. a volume-balance approach) is based on the fact that pore volume should be equal to the fluid volume in the control volume simulation grid.
CVMFE method is used to discretize the flow equations for the pressure and velocity of each phase simultaneously. The CVMFE method provides a more accurate solution because the continuity of the velocity across the control volume boundaries is honored in spite of the fact that flow potential gradients are discontinuous in the heterogeneous anisotropic scenarios. After obtaining the pressure solution, we use a specific CVFE to calculate the molar compositions.
Finally, a comparison of the mixed finite-element formulation with that of conventional finite-difference schemes is shown. Both methods emphasize the multi-scale issue of interaction of various reservoir forces and reservoir anisotropy which must be accounted for when planning a major gas injection project.
Challenges of Wireline Formation Testing and Fluid Sampling in Tight, Low Permeability Gas Reservoirs: Case Study from Saudi Arabia
Authors: Omokaro Felix Abu , Musharfi Nedhal M. , Soliman Wael , Rourke Marvin , Eid Mahmoud 
Published: September 2011

Abstract
Saudi Aramco's operations cover a wide range of environments, some of which are multilayer gas reservoirs, consisting of thinly-laminated shaly sands. Evaluations based on conventional log data often prove to be inconclusive. Wireline formation testers are routine sources of reservoir pressure and fluid samples that address uncertainties in these formation evaluations.
In general, low permeability reservoirs pose numerous challenges for obtaining successful pressure measurements and fluid samples, including supercharging effects and "tight" tests, where no pressure measurements or samples can be obtained. In some cases, tight reservoir permeability prevents an adequate and competent mud cake buildup, which can prevent sealing of the conventional rubber probe type pads. In this paper, the authors share the different approaches employed under some of these challenging conditions in getting representative pressures and samples. Proper selection of tool configuration and appropriate pad and packer design were key success factors.
In the paper, we highlight how to use pre-job modeling to improve pressure testing and fluid sampling.. In our examples, pre-job modeling were done to predict the expected rates and drawdowns. We used dual ports within the straddle packer testing interval, which permits the segregation of gas and the filtrate. This allowed the formation fluid to be sampled faster than a single-port packer design or probe type tool. We also demonstrate how a combination of pad type probes and dual packer helped to enhance the success rate and reduced our pumping time during sampling.
This paper reviews cases of testing in tight gas reservoirs. It also demonstrates how we improved the success rate of our pressure testing and sampling by combining modern wireline formation testing (WFT) functionalities and effective pre-job planning. This approach is helping us meet the challenge of obtaining representative pressures and fluid samples in low permeability formations.
Achieving Target Solids-Free Gas Rate from Highly Unconsolidated Sandstone Formation Intervals
Authors: Abulhamayel Nahr , Solares J. Ricardo , Nunez Walter , Malik Ataur , Basri Mustafa , McWiliams Andrew , Tahir Oumer , Abduldayem Mohammad 
Published: September 2011

Abstract
One of the most challenging aspects of producing wells drilled in the northernmost section of the unconsolidated pre-Khuff gas bearing reservoirs in Saudi Arabia is to achieve solids-free production while trying to achieve high gas rate targets. A high degree of success in meeting this challenge has been achieved by implementing a fracturing for sand control strategy, whereby proppant fracturing treatments with a tip screenout design and a combination of other techniques have been successfully placed in a number of producers throughout the gas development program. Subsequently, challenging reservoir conditions, including high temperature and pressure, high stress, heterogeneity, and the absence of stress barriers make placing the fracture treatments very difficult, time consuming and expensive. Therefore, in pursuit of optimum, simple, and cost-effective solutions to the challenge of achieving solids-free gas production, Saudi Aramco successfully set stand-alone screens in wells completed open hole in a sandstone reservoir, and achieved excellent results while significantly reducing costs by eliminating the need for a fracturing treatment and streamlining all other operations.
This paper provides details about the geology of the sandstone reservoir, well and screens selection criteria, the screens deployment procedure, post-deployment results, and lessons learned from a two well pilot test. The successful results achieved from the pilot test opened the door for further implementation of the technology and optimization steps.
Recent Advances in Pore Pressure Prediction In Complex Geologic Environments
Authors: Huffman Alan R. , Meyer Jeffrey , Gruenwald Robert , Buitrago Javier , Suarez Jaime , Diaz Carlos , Munoz Jose Maria , Dessay Jack 
Published: September 2011

Abstract
In recent years, methods have been developed to enable robust pressure prediction in the presence of multiple pressure mechanisms including undercompaction, unloading processes (secondary pressure mechanisms) and at great depth, the onset of secondary chemical compaction. These models utilize geological and geophysical information to constrain the calibration models and the depths at which they must be applied to develop a multilayer pressure calibration model that will accurately predict pressures for prospect-level analysis and pre-drill prediction. These models are then integrated with the velocity field and the geological and geophysical information to predict pore pressures and fracture pressures at greater depths than have been previously feasible. This methodology has been tested in multiple basins and has been proven to be effective in helping drilling engineers improve well performance through more effective mud and casing program designs that significantly reduces well costs and rig time.
Recent application of elastic and acoustic inversion in complex carbonate environments have also proven effective in predicting pressures in environments where the shales can be separated from the carbonates. The approach requires that the inverted data be separated into the shale and carbonate velocity trends to allow the shales to be used for effective stress prediction while the complete velocity field is used for time-depth conversion. These studies have revealed that pore pressure prediction from mixed lithology (carbonate and shale) environments is feasible using advanced inversion methods. Successful pressure prediction in this type of geology requires seismic data that is of sufficient quality to enable a robust acoustic and/or elastic inversion to be performed that can separate the shale velocities for effective stress calculation, and perform time-depth conversion from the complete velocity field. As the amount of shale present in the geologic section becomes smaller, the ability to predict pressures decreases. The presence of marls also presents a problem because the carbonate material within the shale suppresses the sensitivity of the shale velocity to pore pressure.
Regional Geological Understanding of Offshore Cyprus and Lebanon from Interpretation of Dual-sensor Streamer Data
Authors: Skiple Cecilie , Sortemos Thore , Lie Øystein , Lowrey Caroline J. , Semb Per Helge 
Published: September 2011

Abstract
Dual-sensor cable seismic data has been acquired over the Eastern Mediterranean area. The data has improved the seismic quality, and this has enhanced the understanding of the subsurface of the region. In this paper, we take this dual-sensor data, merged with conventional seismic data to review the offshore areas of Cyprus and Lebanon in the Eastern Mediterranean. The regional geology of the area has been summarized, and the horizons and intervals most significant for hydrocarbon exploration have been described. A brief introduction to the dual-sensor technology and its benefits are described, but the main focus of the paper is to show how the regional geological understanding has been increased based on the new seismic data. Selected regional profiles over the Levantine and Herodotus Basins with their associated areas including the Eratosthenes Continental Block, the Cyprus Arc and deformation front and the Levant Margin illustrate the principal tectonic features and regional key horizons. In addition, specific seismic lines are presented to illustrate particular depositional features, as a possibly large clastic system in the north-eastern part of the Levantine Basin. Isopach maps are used to describe the thickness variations across the area. Parts of the region may contain all the ingredients for a working petroleum system with the key ingredients of potential source, seal, reservoir and trap in place. In addition it is possible that the size, geological complexity and lack of well-data, mean that the existence of ‘yet to be discovered’ play-types in the area cannot be entirely discounted?
Design, Completion and Optimization of High-Pressure/High Rate Offshore Gas Wells
Authors: Uzcategui E. A. , Ahmari A. S. 
Published: September 2011

Abstract
To meet gas demand, Saudi Aramco is developing three new offshore gas fields with a relatively low number of high rate gas wells. These fields have the particularity of having a very high-pressure and high content of H2S and CO2 in its gas composition.
To develop these fields, a concept of multi-slot platforms with highly deviated wells and 7" monobore completion was initially considered. Later, due to several challenges, a full review of the well construction and completion was carried out for these three fields to be able to minimize risks and achieve the production target.
The new development schemes implemented are considering double annulus seals to avoid communication and to ensure proper formations isolation, relocation of the tubing retrieval subsurface safety valve, operational wells cleanup procedure to ensure production solids free at a higher production rate, and 7" and 958 " monobore completion for production tubing to achieve the production target and minimize requirement.
This paper discusses the new development approach and completions, including the basis for the design.
Bioremedation of Oily Contaminated Soil through Biostimulation of Indigenous Soil Microbial Community at the Sahara Desert
Authors: Ercoli Eduardo , Carrillo Gonzalo , El Mansuri Omar 
Published: September 2011

Abstract
Biological treatment has been successfully used to remediate oily contaminated soil in El Sharara Field, South West of Libya. A reduction of 66.6 % in TPH GC Sum, Gas Chromatographic Total Petroleum Hydrocarbon, was obtained in a period of 6.2 months (from July of 2007 to January of 2008). During this time, mineral oil decreased from 15000 to 5000 mg/kg dry matter. The pilot trial consisted in a soil pile of about 2.2 meters in height, mechanically mixed to maintain aerobic conditions. The volume of the pile was approximately 180 m3. The goal of the bioremediation pilot trial was to degrade hydrocarbons by using a low-cost, "poorly controlled" technology which consisted in stimulating naturally occurring microorganisms by adding oxygen (mixing), nutrients and water. One important advantage of the applied technique is that moisture of the soil was maintained at a certain level during the treatment period by adding a minimal amount of water, which is particularly important under the desert working conditions. Another advantages are that contaminants are destroyed, making this a toxicity reduction process that is preferred by the regulators, the treatment systems are relatively easy to design and construct, remediation can be completed in a relatively short time of 3 to 6 months. Mechanically aerated piles offer a cost-competitive technology compared to thermal desorption or landfilling and can be engineered to be potentially effective for any combination of site conditions and petroleum products.
Engineering Approach to Utilize Fiber Optics Telemetry Enabled Coiled Tubing in Well Testing and Sand Stone Matrix Stimulation - First Time in the World
Authors: Shaheen Tarek , El Fattah Mohamed Abd , Dilling Lambert , El Rahman Sayed Abd , Anwar Emad , Noya Vidal , El Refaei Ahmed , Elsherif Tamer 
Published: September 2011

Abstract
For the last several years, viscous pills, polymer based, were used to kill the wells during the workover operation in the tronian formation existing in the eastern desert of Egypt. These polymer pills have negatively affected the wells productivity by blocking the pore throats and reducing the permeability. As an example, the well A-1 was producing 300 bpd (Gross) which declined dramatically after a workover operation which included the viscous polymer pills to produce only 20 bopd.
An engineering study was carried out to identify the main reason for the decline in the production. Several experiments were performed in the lab in order to simulate the filter cake using formation samples and evaluate the effect of the polymer being injected on the sandface permeability. An engineered solution was designed to break the polymer subsequently pumped in the formation and stimulate the matrix in order to recover and enhance the oil production. The remedial work was executed using a Fiber Optics Telemetry Enabled Coiled Tubing (FOTECT) system to optimize the treatment leveraging on downhole real time measurements.
This paper describes the first application of FOTECT in sandstone formations, involving: The sandstone matrix stimulation operation.Measuring both bottom hole pressure and temperatures at static and dynamic conditions during the entire operation.Accurate depth correlation to achieve optimum placement of the treatment fluidsMonitor the chemical reactions in real time of the engineered treatment fluid.Monitor the diversion performance during Sand Stone stimulations and the timing required for efficient reactions.Qualitative production allocation of the interval as a response to the treatment fluidsEvaluation of the skin value real-time while executing matrix stimulation.Pressure transient analysis in real-time enabling the standard output of a well test (permeability, skin, Pressure, and reservoir boundaries).
The experience demonstrates that use of real-time downhole measurements during the CT treatment allows: a) the evaluation of the well performance before and after the treatment, b) enables optimization of the treatment as it is executed, based on the formation response, enhancing the chance for a successful intervention, and c) provides an added alternative to perform a well testing operation right after the treatment, thus, obtaining valuable information to update the reservoir model.
Risk Analysis Tool Applied to Understand the Possible Negative Environmental Effects of Unlined Drilling Pits in Desert Environments
Authors: Carrillo G. , Rubial M. J. , Firth S. 
Published: September 2011

Abstract
Traditionally in desert operations in Libya, drilling mud and cuttings (water based) have been disposed of directly on the ground in unlined pits. This practice has lately been challenged because other than affecting the landscape, it can pose a risk to the soil and to shallow aquifers.
To correctly assess the risk that this practice poses, REMSA and specialized environmental consultants developed a tool to predict the risk of pollutants transported by lixiviates reaching shallow aquifers below the drilling pit itself.
The model has the capacity of determining the threat of a group of pollutants individually moving from the pit through the Unsaturated Zone. Other than modeling the movement driven by gravity, the model also considers biodegradation of organics and absorption processes within the Unsaturated Zone and dilution once in the Saturated Zone.
This modeling tool (CREWD) has been tested in block NC186 in Libya and the results have been validated throughboreholes and excavations that reached down 4 meters below the bottom of the pit. The results obtained using the model, gave a clear indication that with the prevailing conditions in NC186 and knowing that the shallowest aquifer mapped is below 60 m depth, the risk of hydrocarbons, heavy metals or salts causing detrimental impact to the aquifer is extremely low.
Industry First Field Trial of Reservoir Nanoagents
Authors: Kanj Mazen Y. , Rashid Md. Harunar , Giannelis Emmanuel P. 
Published: September 2011

Abstract
The promise of nanotechnology becomes limitless with the possibility of having functionalized molecular agents to "illuminate" the reservoir and intervene to alter adverse oil recovery conditions. The future reality of the reservoir nanoagents concept is herein lab and field demonstrated with the industry first building block nanoagents' template. The template is intentionally geared towards the harsh but prolific Arab-D carbonate formation of the giant Ghawar field of Saudi Arabia. The challenge is magnified by a condition of 100 °C or greater temperature and 120,000 ppm or more connate water salinity. The industry's first proven reservoir nanoagents template is introduced and demonstrated via a push-pull field trial in an observation well. The testing objectives, processes, and results are outlined and further detailed in the paper.
Well and Reservoir Behavior with Varying Associated Gas/Oil Ratio
Authors: Lundberg Bruce 
Published: September 2011

Abstract
A production well may experience varying associated GOR if the reservoir has a gas cap which gains access to the well (e.g. GOGD or Gas Coning), or if stationary oil near the well liberates gas due to near-well pressure drawdown (Liberated Gas). This Free Gas inflow rate varies disproportionally with well production, resulting in varying associated GOR.
Production wells in fields producing varying associated GOR are often susceptible to well instability and excessive gas breakthrough, where Free Gas is produced at unacceptably high rates. Operational control of these wells with manually adjusted chokes or beans is hampered because well behavior is highly non-linear and displays severe hysteresis.
A common scenario is: 1)A well produces at low liquid rates with little or no free gas production.2)Moderate increases in liquid production are achievable without gas breakthrough.3)At some point, a minor further increase in liquid production results in gas breakthrough and unacceptably high free gas production.4)Choking back the well moderately does reduce some free gas production, but an acceptable level of gas is not obtained until the well is choked back so far that liquid production is reduced to an unacceptably low level. Sometimes wells are stopped for a period in order to recover and resume production at acceptably low gas rates (Stop Cocking).
This complex production behavior, where the same choke position produces different production results, has often been attributed to complex or unpredictable reservoir drainage dynamics. A theory is developed in which this production behavior can be explained with simple, intuitive reservoir dynamic drainage models and standard well performance models.
The theory explains limitations of production control using manually adjusted chokes or beans and provides a basis for the development of simple automated well flow control systems which stably maintain optimal production.
Petroleum Development Oman has successfully applied automated well flow control on more than 90 wells with varying associated GOR. Many of these wells had previously been Stop Cocked and all are now continuous producers. The resulting stable, predictable production from each well is a necessary foundation for field-wide production monitoring and optimization.