bluuebunny/crossref_metadata_2025 huggingface dataset:
A Cohesive Technique to Optimize an Openhole Multistage Acid Frac in Unconventional Oil Reservoir - North Kuwait
Authors: El-Aziz Sabry Abd , Chin Chao , Ashqar Ayham , Al-Ajmi Moudi , Mauro Rick , Nada Mohamed , Nada Mohamed
Published: November 2017

The combination of horizontal wells and multistage fracturing enabled the development of tight carbonate reservoirs. The successful completion of these reservoirs can be challenging. Correct placement of multistage intervals plays a critical role in improving and sustaining production. Openhole (OH) multistage (MS) technologies enhances reservoir contact and productivity by optimizing the distribution of the stages across the openhole. This paper presents an engineering technique to optimize OH fracture stages and cluster placement distribution within heterogeneous unconventional oil carbonate reservoirs based on formation, completion properties, and reservoir fluid distribution.

Completion technology is based on distributing intelligent packers along the lateral section to develop the MS fracturing stages. Intelligent packer displacement influences fracture effectiveness and conductivity. Equal spacing packer placement can undermine formation potential and productivity results. The placement of the packers and their ports is based on the petrophysical and mechanical properties of the formation to increase the cumulative production in a shorter timeframe and to help improve recovery. The method followed is based on an analysis of the reservoir properties (porosity and permeability). These were later integrated with the measured rock mechanical properties. The developed integrated model was used to categorize the rock into segments that share similar properties.

The use of an advanced azimuthal sonic tool with a high signal-to-noise ratio and wider frequency response helped to improve the accuracy in assessing formation mechanical properties. In addition, conventional logs, when combined with formation mobility measurements, help to calibrate the permeability model and classify the formation into distinctive clusters. These clusters are then grouped according to their mechanical and brittleness properties to form a separate unit with a selected fracture port to help ensure the necessary fracture length. The developed method provides an opportunity to determine the necessary fracture stages and to reduce the risks of overor underplacement. It also improves stage integrity, helps to ensure better distribution of the acid across the formation matrix, and provides effective propagation of the fracture network.

The applied procedure follows an innovative approach to optimize the fracture stage and cluster placement distribution across the reservoir using a new combination of advanced and conventional data acquisition and interpretation. The case study presented in this paper demonstrates the benefits of engineered fracturing stage placement, as compared to a geometric displacement.
Importance of Borehole Images and Dipole Sonic Data for Optimal Stimulation in a Tectonic Compressive Setting
Authors: Gamero Diaz H. , Mohsin L. , Desroches J. , Waters G. A. , Peralta J. D. , Al Zeidi O.
Published: November 2017

Interpretation of logs from an exploration pilot well and a lateral drilled from the pilot in the Late Cretaceous Natih formation in the Sultanate of Oman was used for designing a multistage hydraulic fracturing treatment. A high-tier logging suite including borehole image, advanced dipole sonic, geochemical, and triple combo data was acquired in both wellbores. The objective of the pilot hole was to select the best landing point in terms of reservoir quality (RQ) and completion quality (CQ) so that a horizontal well could be drilled and multistage stimulations performed in the organic-rich Natih B source rock.

In contrast to much of North America, significant tectonic forces are frequently present in this region. The geomechanical setting might thus strongly affect hydraulic fracture initiation, propagation and proppant placement. It therefore plays an important role in lateral landing point selection. Borehole images, integrated with petrophysical and geomechanical log properties, were used to identify the optimum landing zone. Breakouts as well as longitudinal and transverse drilling-induced fractures were identified on the pilot borehole images over the Natih Formation, indicating a large horizontal stress anisotropy and a compressional tectonic setting. An interval from which vertical hydraulic fractures would initiate at low initiation pressure and grow vertically to contact intervals with good RQ was selected as the target lateral landing point. Image and dipole sonic data were acquired in the horizontal well, and both longitudinal and transverse induced fractures were identified. Those data were used to selectively place hydraulic fracturing stages. Diagnostic injection tests on each stimulation treatment confirmed low fracture initiation pressures and the creation of vertical hydraulic fractures, thus validating the selection of both the landing point and the location of the hydraulic fracture initiation points. All treatments were successfully placed to completion.

This paper demonstrates that a workflow based on the combination of image and dipole sonic logs in both a pilot well and a lateral drilled from the pilot enables the creation of vertical hydraulic fractures at moderately low initiation pressures and successful placement of stimulation treatments in the lateral. This technique shows promise for effective hydraulic fracturing in regions where significant tectonic forces are present.
Integrated Workflow For Building 3d Digital Outcrop Models Using Unmanned Aerial Vehicles - Drones: Field Case Thamama Group, Wadih Rahbah, UAE.
Authors: Parra Humberto , Salgado Gomes Jorge , Shebl Hesham
Published: November 2017

The aim of this paper is to provide an insight on the usage of unmanned aerial vehicles (drones) for capturing 3D photorealistic images of geological outcrops which can be used as digital analogs during 3D geological modelling.

Recognizing the potential of the use of drones in many other fields has opened the doors for an endless variety of applications in the geoscience world as well. Specifically, in geological mapping and 3-D modeling activities, the use of these technologies can be seen as a cost-effective method of quickly and accurately surveying, mapping and capturing surface geological phenomena and processes that were more difficult and expensive for been surveyed in the past.

Combining aerial and ground photography acquisitions, the image of geological outcrops can be captured and modelled in 3D using photogrammetry techniques, generating Digital Elevation Models (DEM). With DEM the users can perform measurements in multiple azimuths and compare and overlay geological, geophysical and petrophysical data at different scales and obtain multi-point statistics (MPS) for MPS modelling or conventional spatial statistical information for variogram analysis. Jumping ahead from the past where data was used for only qualitative comparison through pictures, the outcrop data can be used directly as a cloud of points to be used as 3-D wireframes into modelling software for enhancing reservoir architecture procedures (designing vertical layering schemes on grids) capturing reservoir heterogeneities at different scales.

The creation of digital outcrop models using drone technologies is a cost effective solution to introduce the advantage of the field observations into more accurate subsurface models. The advantage of incorporating outcrop information into the geological modelling workflow is the ability to understand, based on direct observations of the complexity of the geological drivers, which one plays the major control on the property distribution and flow processes in the subsurface.
The Successful Application of One Run Drilling Technology in Big-Thickness Halite Formation of Ultra-Deep Water
Authors: Liqiu Ping , Xi Wang , Rong Li , Rui Yang , Chenchao Liu
Published: November 2017

The drilling operation in the more than 2000m thickness pre-salt formation with more than 2000m water depth faced great challenges from the beginning in X. Project of Atlantic due to drill string stuck caused by salt creeping and low ROP, so efforts were concentrated to obtain a better drilling performance as a consequence of the high daily rates of drilling ships.

In this paper, we look for a combination of high performance PDC bits, near bit reamer stabilizer, synthetic based-based mud, MPD, RSS and LWD systems to increase the drilling performance, both in ROP and salt creeping control in salt formations. ROP has been increased by more than three hundred percentages by high performance PDC bits. Near bit reamer stabilizer and synthetic based-based mud made drill string stuck frequency decrease drastically. The combination of MPD, RSS and LWD systems has improved drilling performance. The above-mentioned integrated drilling technology has been successfully applied in two pre-salt wells in one run whose halite formation thickness is 1870m and 2062m respectively in 2016.

The drilling duration for 2062m salt section has decreased to from 14 days to 7 days which saved about 14 millions dollars for the two wells. The average ROP record of the two wells by use of the integrated drilling technology is 24.6 m/h that has been improved 3.4 times comparing the completed four wells in 2015 in X. Project. The NPT caused by drill string stuck has been decreased from the average 11.7 days to zero that can save about 12 millions drilling cost. So the integrated halite drilling technology can not only solve the drilling problems in halite formation in ultra-deep water such as bore hole collapse and drill string stuck but also increase the ROP. The drilling performance in halite formation has been improved and the integrated halite drilling technology has been widely applied in big-thickness pre-salt formation Santos basin and will decrease the drilling duration of ultra-deep water pre-salt reservoirs wells and lower the oil cost per barrel in ultra-deep water development.

The method to increase drilling efficiency in halite formation of this paper presented will make a reference for deep water salt formation drilling and offshore oilfields high efficiency development. Also the method to control salt creeping and drill string stuck might give a light to the drilling operation in gypsum formation in onshore oilfields.
The First Successful Combination of an Electro-Mechanical Pipe Cutting Tool with the Intelligent Coiled Tubing System to Perform Cuts at a Deep-Water Horizontal Well in Brazil
Authors: Carvalho Ricardo de , Barrros Robledo Wakin , França Cícero Rondinelli , Silva Deylla Gomes
Published: November 2017

This paper describes the efficiencies of deploying the electro-mechanical pipe cutting (EMPC) tool with intelligent coiled tubing, highlighting the advantages of this tool compared to existing ballistic, chemical and other mechanical tools in terms of precision, time cost savings and HSE performance. The paper also covers the added advantages generated through the use of intelligent coiled tubing on the overall operation.

The recent introduction of intelligent coiled tubing equipment, incorporating real-time downhole tool capabilities, data communication transfer and power supply, has made possible the deployment of the electro-mechanical multiple cutting tool on coiled tubing. The emergence of this technology enables the cutting tool to perform operational applications previously unachievable in long horizontal wellbores. In the deepwater environment, there is an expectation of an increase in plug and abandonment projects. This increase will create new challenges relative to cutting and retrieval of the completion tubing. The electro-mechanical cutting tool has been proven in recent years to be an extremely reliable, efficient, and safe method to perform cutting operations in tubulars, sand screens, as well as releasing packers in high-pressure environments. The paper presents a case history detailing this methodology and the involved pre-job planning, deployment risk and management modeling, demonstrating and concluding the completeness of this solution and its reliability.

The paper shows how the combination of intelligent coiled tubing with the electro-mechanical cutting technology can render the usage of ballistic, chemical and other mechanical devices as unnecessary and outdated/inefficient.
ADNOC Journey in Developing an Unified Value Assurance Process for Capital Investment Projects
Authors: Khalil Tariq , Balsubramanian Nagarajan , Lugon Patrick
Published: November 2017

The oil and gas industry performs significant investments in complex and risky environments to develop their Project portfolio.

To improve the efficiency of capital investments most of the Oil & Gas (O&G) companies assess the projects value by performing intermediate reviews before approving major milestones of a project that will authorize further investment.

ADNOC as many others was willing to improve capital efficiency and initiated its own process in 2014.

We will present in this paper the ADNOC journey in developing its Value Assurance Process for capital investment projects; how projects are classified, and how project reviews are set up upfront of the approval gates; the new Value Assurance Process put in place across upstream operating companies and key principles that will be applied for the development of opportunities.

Let us start the journey!
Modelling of Casing Reciprocation During Cement Displacement in ERD Wells
Authors: Sissenov Olzhas , Ruzhnikov Alexey
Published: November 2017

Ensuring a quality cement job when cementing long sections of casing in high angle, extended reach wells is both critical and challenging due to the high risk of channeling and pressure related issues. Casing reciprocation is intended to mitigate against channeling; however, this technique is not widely used in ERD wells in the industry. This paper presents modeling, operational observations, and the results of 10¾-in production casing reciprocation during cement displacement on several extended-reach drilling (ERD) well projects.

Accurate estimation of hydraulic lift force is one of the major challenges when planning casing reciprocation during cement displacement. The severity of the hydraulic lift force can cause the complete loss of slack-off weight when reciprocating on the down stroke, which is often perceived as the casing being "set" off-bottom. In order to accurately predict the hydraulic lift force and the associated hookload fluctuations, advanced modeling combining torque, drag, and hydraulics was developed. The model takes into account all of the key parameters such as slurries density and rheology, displacement rates, casing stroking speed, wellbore geometry, temperature and pressure effects, etc.

In excess of 10 casing reciprocation jobs during cement displacement have been successfully modeled and executed to date. The first several wells were used for model calibration, and the modeled loads for the remaining wells showed consistent and accurate predictions when compared with the measured loads during the cement displacement. The casing strings that were modeled and subsequently reciprocated during cement displacement varied in setting depths from 2000 to 3100 m MD, with the top of cement lifted to the previous casing shoe. It was observed that the effective hookload when stroking the casing down can significantly decrease when the hydraulic lift force is high due to the combined action of surge and circulating pressure. Slack-off hookloads were monitored in real time to determine cementing friction factors. The friction factor data allowed for calibrating the model, which gave confidence to continue reciprocating throughout the entire displacement until bumping the plug. The casing reciprocation campaign has contributed to an increase in the quality of the cement bond throughout the casing string, thereby no longer requiring any remedial cement jobs, which was a common requirement on the previous wells.

The technique and observations presented in this paper help close the gap that exists in the industry concerning the effect hydraulic lift force has on casing reciprocation operations. Understanding the effect is important in ERD wells, but can also be useful on other types of wells.
High Power Laser Technology in Downhole Applications, Reshaping the Industry
Authors: Batarseh Sameeh I. , Graves Ramona , Al Obaid Omar , Al Hartih Abdullah , Othman Haitham
Published: November 2017

This paper presents an innovative non-damaging technology as alternatives to current downhole conventional practices. It will change the industry and reshape several downhole applications such as perforations and fracturing among others. It is proven to provide not only non-damaging technology, but also improves flow properties and enhances communication between wellbore and formation.

For several years, researchers attempted to deploy high power laser technology for several downhole applications due to its accuracy, precision, control, consistency and power. The laser source is located at the surface on the coiled tubing unit, power generator provides power to the system and high energy is transmitted downhole via fiber optics cable to the targeted zone, the laser energy is manipulated and controlled through downhole laser tool to perforate and create tunnels connecting the wellbore with the hydrocarbon bearing formation. One of the main challenges is conveying the energy downhole with minimum loss through fiber optics. This paper will present the potential of the laser in reshaping the industry and change the current practices.

High power laser is proven to enhance flow properties in all types of rocks regardless their compressive strength and hardness, the unique features of the technology are the precision in controlling and orienting the energy in any directions regardless of the reservoir stress orientation and magnitude. It can be targeted directly to the pay zones and produce from bypassed zone that can't be achieved with current technology such as fracturing. Lasers provide safe, small footprints and environmentally friendly technology since it is a waterless base technology for connecting the wellbore with the formation (alternative to water base fracturing technology).
Hydraulic Study of a Horizontal Well to Compare Dual Horizontal-Vertical versus Single Vertical Completion
Authors: Alshmakhy Ahmed , Caicedo Sergio
Published: November 2017

With recent advancement of horizontal well drilling, longer wells have been drilled extensively. Initially, it was thought that when long wells are drilled, productivity would increase linearly. However, field experience proved otherwise. Many wells showed more production from heel side as witnessed by production surveys. The effect of introduced friction losses becomes significant when applied drawdown is closer to expected pressure losses making it difficult to produce away from heel. The objective of this work is to study the hydraulic flow aspects of a horizontal well in cases of single and two entry points.

A well, in an Abu Dhabi field, was equipped with a dual string in the horizontal section after a work over event to replace the standard single completion. The dual strings are separated by swellable packers and run so short string produces the upper segment while the long string produces the lower segment. Full hydraulic analysis is conduced to understand flow behaviour and associated pressure loses in both annular and tubing sections for both strings. A full scale of data gathering was executed including multi rate tests, production logging, and different flow setting with flow from strings separated and commingled at different choke settings.

Simulation cases have been developed to study flow from single standard tubing and dual, short and long strings, with theoretical and history matched scenarios. The resulted vertical lift performance curves are introduced to a coupled wellbore-reservoir model and production curves have been produced for various flow scenarios. This workflow provided a comprehensive method to choose the most appropriate method as an alternative horizontal well completion and demonstrated the value in terms of oil gain and water reduction as well as improved well accessibility.

The simulation study results showed an increased well productivity with multiple entry points, at heel and toe, especially with long wellbores in line with field results. In addition this alternative completion method allowed well accessibility and improved skin towards toe improving well productivity. Field results confirmed directional simulation results with more than 30% incremental production for each segment and full toe accessibility. This integrated approach provides a guideline on choke selection to confirm transport of produced fluids and mitigate issues with liquid hold up associated with production at high water cut.

The studied alternative method aims to encourage flow from both compartments of the wells with simple dual completion configuration versus the standard single completion. Application of this alternative completion method in early stages may be crucial to mitigate potential well issues that are difficult to cure later in well life. This paper provides a guideline using field cases and advanced coupled reservoir wellbore simulation to optimize well performance with cost effective techniques using currently available industry tools.
In situ Wettability Measurement in a Carbonate Reservoir Rock at High Temperature and Pressure
Authors: Alhammadi Amer M. , AlRatrout Ahmed , Bijeljic Branko , Blunt Martin J.
Published: November 2017

More than a trillion barrels of oil may be extracted from carbonate reservoirs in the Middle East. Oil recovery is known to be controlled by wettability (distribution of contact angles) that determines the pore-scale fluid configuration. However, these contact angles have not hitherto been measured in situ at reservoir conditions for reservoir rock that is saturated with formation brine and crude oil. We use high resolution X-ray imaging of a sample from a producing oil field to demonstrate that contact angles over a wide range are seen both above and below 90°. More than a million points of contact angle were measured after three pore volumes of formation brine flooding. The injected brine invades the center of the pores as a non-wetting phase leaving oil trapped in small pores and corners in connected layers.

Pores that were filled with initial formation brine remained water-wet. On the other hand, surfaces that were in direct contact with crude oil during aging were altered to oil-wet. However, water-wet surfaces were also measured in pores that were filled with crude oil which suggests that water layers in small pores, crevices, and within rock surface roughness, which might be connected to brine in micro-porosity, could prevent the contact between surface active polar compounds in the crude oil and the rock surfaces preventing strong wettability change. The reservoir rock became mixed-wet with a mean contact angle of 106° ± 20° obtained from 1.36 million in situ contact angle values measured using an automated algorithm (AlRatrout et al., 2017) applied on segmented three-dimensional X-ray image. The three-dimensional images were acquired using a high resolution X-ray micro-tomography scanner. The wetting condition resulted in a large volume of oil (50.6%) being trapped with a distinctive morphology as rough sheet-like layers.
CORAL 2.0: Forging Collaboration towards Industry Cost Competitiveness in Malaysia
Authors: Ali Hajejah , Mohamad Nurul Azni
Published: November 2017

Since early 2015, PETRONAS, through its Upstream Regulatory Unit (Malaysia Petroleum Management (MPM)) drives and coordinates an organized nationwide response to recent downturn of oil prices starting late 2014. Building on collective intelligence of the leaders from its Petroleum Arrangement Contractors (PACs), Oil and Gas Services and Equipment (OGSE) providers as well as PETRONAS’ internal organization, a cost optimization program, which termed as Cost Reduction Alliance (CORAL) 2.0 was defined to take Malaysian Upstream industry through a cost transformation journey, with the mission to optimize cost, improve efficiencies and drive innovation towards a new level of industry competitiveness. This paper documents the framework of this program and its key principles guiding the whole program execution. Several observations concerning its impact to Malaysian Upstream industry are also deliberated.
Sand Control Technology for Extended-Reach Wells: Best Practices from the Longest Gravel Packs Performed Offshore Brazil
Authors: Colbert F. C. , Costa A. L. , Gachet R. F. , Garcia F.M. , Neto A. T
Published: November 2017

The Campos basin is a sedimentary basin located in offshore Brazil, between the north coast of Rio de Janeiro State and the south coast of Espírito Santo State, encompassing many oilfields. Most of the reservoirs in the basin are high-permeability sandstones containing low API gravity oil but are without strong water drives. Long horizontal producer wells are the best economic option for field development but require water injection to maintain reservoir pressure. Horizontal sections generally range from 1000 to 2000m, which demands gravel pack as a sand control method. Gravel packing such long wells is a challenge and requires thoughtful engineering to optimize pumping techniques and technology. Presented here are best practices to overcome several challenges faced in this field to achieve overall success.

The challenge for extended-reach gravel packing is that the long horizontal section develops high friction during the alpha and beta wave propagation. Increasing the pumping pressure to overcome this friction increases the risk of fracturing the formation, consequently reducing the equivalent circulation rate downhole impairing the proppant transportation. In contrast, a reduced pump rate during alpha wave propagation can lead to a premature screenout due to the increase in dune height of over 85%. To overcome these issues and place gravel packs in these wells, careful engineering and simulation, lightweight proppants, friction reducers, and thorough job planning were used to successfully perform gravel packs in more than 40 horizontal wells completed in the Campos basin from 2011 up to 2017.

The experience of pumping the longest gravel pack jobs in offshore Brazil (horizontal length more than 2,000m) offer insights into best practices for gravel packs in extended-reach horizontal wells: Design considerations, specific well challenges faced, technologies deployed, and operational planning requirements. Specifically, highlighting the benefits of using lightweight proppants and optimized fluid systems to minimize screen out risks and maximize pack efficiency.
Alternative Framework for Structural Integrity Management of Jacket Platform Beyond its Design Life
Authors: Kongchang A. , Danthainum A. , Chattratichart T. , Sonachai P. , Thavornsuk T. , Katanyoowongcharoen S. , Sriparagul J. , Kosanunt P.
Published: November 2017

This paper presents an alternative to conventional approach where extended service life of an offshore structure is traditionally quantified by fatigue limit state. The paper provides Structure Integrity Management (SIM) framework relied on qualitative approach which determines prediction of extended life and optimised inspection strategy. The ultimate strength assessment is correspondingly deemed necessary to eliminate failure mode induced by fatigue crack. By which, the fitness-for-purpose of jacket structure with relatively low fatigue life can possibly be assured without the need of additional periodical level IV survey, degradation, modification and other functional mitigations.

Basic SIM framework is a cyclic process based on evaluation of original design and inspection findings throughout platform service life. A reassessment of existing structure is required after its original design life exceeded. The additional work process will be jointed to four main processes of SIM to refine the redundancy level. The prediction of extended life is determined using qualitative information in relation to nature of fatigue crack that rarely found on jacket structures installed since late 1980 in various locations around world.

Practical application of the alternative SIM framework is illustrated using an example of structures installed at 80 meters of water depth in Gulf of Thailand. The SIM program has been triggered since 2012 by essential operability beyond design life. Various refined levels of design approach could not provide extra service life due to change of metocean, and facility upgradation. It was thorough challenges to define a scheme which could present both acceptable risk level and optimised cycle. The ultimate strength assessment is carried out and it justifies survivability level on both intact and damage conditions of structures against environmental load at 1,000 to 10,000 years depending on their structural robustness. This higher level of assessment proves that low fatigue life joint of jacket structure does not significantly influence platform failure mode. The one-off level IV survey also confirms the irrelevance of fatigue. The qualitative extended life is predicted by this physical confirmation. The evaluation of SIM framework concludes that predicted life can be 2 to 3 times larger than original fatigue life.

The evaluation proved that fatigue does not influence to failure of existing offshore structure. The level IV survey to detail surface crack is not necessary over the period of extension. Unless, other initiators (i.e. anomalies, accident and etc.) require ad-hoc level IV survey. The level II and level III using FMD technique are only remaining part of inspection program.
Mechanical and Corrosion Performance of Corrosion Resistant Alloy Tubing after Long Term Use in Corrosive Gas Well
Authors: Suzuki Y. , Ueyama M. , Sagara M. , Amaya H.
Published: November 2017

For stable production of oil and gas, it is critically important to select appropriate OCTG materials suitable for each well condition. This selection is based on a combination of established material selection charts, know how, fit for purpose testing and life cycle costing. This paper provides and overview of the material selection process and details of the investigation results carried out on a CRA material exposed for a long term to a corrosive production environment.

For flow-wetted sections, the approach of material selection is substantially complex. Not only a thorough corrosion assessment based on the anticipated well conditions, but also selection of corrosion mitigation method using Life Cycle Analysis shall be considered. After that, a final material selection can be conducted.

Material selection was conducted for the harsh field and the selected material has been used for almost 15 years in actual H2S containing well. Investigations like mechanical properties, microstructure, corrosion resistance and surface passive film analysis were conducted.

Based on the well condition at the harsh field (CO2 = 115psi, H2S = 45psi, Bottom Hole Tmeperature = 104°C/220°F), UNS No. N08535 was selected.

7" Tubing of UNS No.N08535 with 110ksi grade has been used for almost 15 years in the above field, and retrived from the well.

The investigation carried out on the retrived material revealed that the amount and extent of sustained corrosion damage is virtually nil. The mechanical characteristics and the corrosion resistance are comparable with newly rolled material. These results indicating that the 15 years of down hole sour corrosive sevice had no negative effect on the material integrity.

In addition, surface analysis revealed that a thin sulfide film containing nickel and molybdenum was observed on the surface of the used pipe. This results well corresponds to the film formed on the specimen surface in the laboratory corrosion test under a simulated well condition, thus validating the fit for purpose corrosion testing approach usually applied when confronted to hostile environment applications.

This also validates the material selection process used and the integrity of UNS N08535-110ksi grade for this application.

This paper is the opportunity to access and analyze a CRA material which sustained long term exposure to a corrosive gas environment characterized by acid gas partial pressure of 115psi and 45psi H2S at a temeperature of 104°C/220°F

The Novelty of this paper is to show the performance stability of CRA during long term use under actual corrosive well condition and reliable selection for OCTG materials.
Optimization of Infill Development in a Highly Heterogeneous Giant Offshore Carbonate Reservoir
Authors: Kohata Akihiro , Willingham Thomas , Tiwari Anupam , Al Sowaidi Alunood
Published: November 2017

The subject field is a highly heterogeneous giant offshore reservoir. Current field development is predicated upon line drive water injection with 1 km spacing; however, it is anticipated that some oil will be bypassed due to geologic heterogeneity. In order to address the bypassed oil and improve recovery, a simulation study evaluating infill well potential for the target reservoir and an optimization of the full field development plan with infills was carried out.

This reservoir consists of two geologically similar areas which are a "Homogeneous" area and a "Heterogeneous" area. High permeability streaks (HKS) having ten times higher permeability than the matrix permeability are dominant in the Heterogeneous area while HKS are significantly less prevalent in the Homogeneous area. Two sector models which represent the Heterogeneous and the Homogeneous areas were generated and sensitivity simulations were carried out to evaluate the vertical and lateral placement of infills. Based on sector model findings, full field simulations were carried out to generate an optimized full field development plan with infills.

As a result of sector model simulation for the Heterogeneous area, infill wells showed higher recovery relative to the "No Infill" base case. Vertical and lateral well placement on infill location had little impact on the oil recovery. This is because the HKS in the upper layers were water-saturated by historical water injection from the base 1 km development; hence, water breakthrough at infill wells occurred from HKS within a short period of time wherever infills were drilled. For the Homogeneous area, infill wells showed slightly higher recovery but no oil plateau extension and high water production relative to the "No Infill" base case. Based on these findings it was concluded that (i) infills were required for Heterogeneous area and (ii) infill are not recommended for the Homogeneous area. For the full field evaluation, three different infill scenarios (i.e. 500m spacing infill implementation, 375m spacing infill implementation and no-infill implementation) were evaluated. The optimal infill development scheme for each pattern was chosen by comparing the production performance of each pattern of these three simulations. As a result, in the optimized infill case, infill wells were required primarily in the Heterogeneous area and were not required for the Homogeneous area.

Through this analysis, the impact of geological heterogeneity on the performance of infill wells and incremental oil recovery was assessed and the full field development plan was significantly improved. Based on these findings the resulting full-field development plan (i) minimizes the number of infill wells required, (ii) optimizes incremental oil production by addressing the bypassed oil.
Workflow for the Estimation of Initial Water Saturation in a Low Permeability Carbonate Reservoir in a Marginal Field and its Impact on Field Development Planning, Case Study from Abu Dhabi, UAE
Authors: Khan Muhammad Faisal , Maskari Shaymaa Ali , Voleti Deepak Kumar , Kundu Ashish , Al-Rawahi Ali Salem
Published: November 2017

It is always a major challenge to estimate accurate initial water saturation in low relief/marginal fields. Several methods for calculating water saturation have been proposed in the industry, however each method has its limitation and relying on any single method will have direct impact on field development planning in early stages of the field. The objective of this paper is to present workflow that integrates multiple methods and help in defining uncertainties associated within each method to finalize water saturation model.

Different methods such as, resistivity, dean stark, sigma, NMR and capillary pressure (Pc) approach were used to estimate accurate initial water saturation. The Sw resistivity method was computed using Archie's parameters such as; log derived deep resistivity and electrical properties from the SCAL data eg: cementation factor (m) and saturation exponent (n). The sensitivity analysis was performed to find which parameter contributes more to Sw uncertainty. Sigma method was used to compute Sw independent of resistivity. The main sigma inputs are sigma matrix, sigma hydrocarbon, sigma water and porosity. NMR was used to compute Swirr using total NMR porosity and free fluid porosity, it helps to bracket the minimum water saturation of the field. The capillary pressure approach was used for saturation height function (SHF) by grouping the Pc data into Petrophysical Rock Types (PRT). The Skelt Harrison function was used to fit Pc shapes observed in different rock types to develop SHF.

The Sw sensitivity analysis indicates that water resistivity (Rw) and saturation exponent (n) have a minimal contribution to Sw uncertainty compared to the cementation factor (m), therefore variable m approach was used to narrow down uncertainty. Three different models for Sw_log were derived (minimum, base and maximum) as strong relationship were found between Petrophysical Groups (PGs) and m values. In order to get an accurate Sw_sigma computation, Sigma matrix and porosity indicate very little impact on Sw_sigma, whereas Sigma water found to be the highly uncertain parameter, due to the mixing of mud filtrate (Faisal. et. Al,. 2016) since the reservoir is in transition zone and the measurement's volume of investigation was shallow. Dean stark approach was also not reliable due to the invasion effects found. For the SHF, the Pc data was grouped into five PGs in which the best rock is characterized with a smaller (Pd), better pore size, and lower Swi. The workflow explains different ways and aspects of Swi estimation and gives interpreter the range of Swi uncertainty to do dynamic parameter sensitivity for optimum field development planning.
Successful Field Trial of a Shear-Resistant, High-Injectivity, Reservoir-Triggered Polymer
Authors: Chappell David , Stapley Jon , Rashid Bilal , Towns Martin , Andrews William J. , Kiani Mojtaba , Salehi Mehdi
Published: November 2017

This paper describes the successful execution of an inter-well field trial to test a novel reservoir-triggered polymer technology (the Polymer) which has been proven to mitigate two of the major operational and economic challenges facing polymer injection for enhanced oil recovery (EOR), particularly in the offshore environment. The challenges of shear degradation and reduced injectivity are overcome by delaying the development of viscosity until the Polymer is in the reservoir.

The field trial was conducted in an onshore sandstone oil field in Texas. The 1,000 ppm Polymer solution was injected at rates of 500 to 900 bbl/d into a 10-ft interval of low water permeability (50-100 mD) under matrix conditions. To demonstrate development of its expected viscosity in the reservoir, the growing Polymer bank was sampled from an existing producer. Pressure Transient Analysis (PTA) was used to confirm the deep-reservoir behaviour of the Polymer.

Field data demonstrates that the Polymer behaves as intended. The viscosity of the produced Polymer samples corresponds to the target viscosity as determined from surface activation of the Polymer at the same concentration. This confirms the shear-stability of the Polymer in its un-triggered form. In addition, the injection pressures were no greater than expected and significantly lower than the expected injection pressures, under matrix conditions, for an equivalent partially-hydrolysed polyacrylamide (HPAM). PTA indicates a bank of fluid of increased viscosity some distance from the injector, as designed.
The Application of Geological Concepts for Various Types of High-Permeability Streaks to the Full-Field Simulation Model History Matching of Carbonate Reservoir, Offshore Abu Dhabi
Authors: Shibayama Akira , Hamami Mohamed Tariq , Yamada Tatsuya , Kohda Atsuro , Farhan Zahra Abdulla , Bellah Sameer , Shibasaki Toshiaki , Jasmi Sami Al
Published: November 2017

This paper presents a case study of full-field simulation model history matching by applying geological concepts for various types of high-permeability (high-K) streaks.

An Upper Jurassic reservoir in "Field-A" is domal shape structure and reservoir fluid is under saturated with bubble point. Field-A has been producing oil from the reservoir for 30 years with total 20 oil producers, by evolved through the secondary recovery stage, such as crestal auto gas injection (non-miscible gas), then shifted to crestal water injection to maintain reservoir pressure. The fluid monitoring results and water-cut/GOR evolution trend indicate complexity and heterogeneity of the reservoir.

Two type of high-permeability streaks associated with stromatoporoid lithofacies in the upper part and fault related fractured dolomite in the lower part of reservoir were identified through the reservoir characterization studies. The zones having the high-permeability streaks show higher well-test KH compared to the core plug based matrix KH. Model KH of the zones including high-permeability streaks were conditioned by maps of the excess KH with the following concepts:

Stromatoporoid lithofacies:

Excess KH map was generated based on the relationship between well-test KH and stromatoporoid lithofacies thickness.

Fault related fractured dolomite:

Core observation indicates high density of open fractures is detected in dolomite of specific layers in the lower part of reservoir. Excess KH map was generated based on the relationship between excess KH and fracture density distribution estimated by 3D seismic dip attribute (fault location dependent)

Through model history matching, stromatoporoid thickness distribution in-between well control points were adjusted to modify excess KH map as one of the major uncertain parameter in the global level matching phase, considering its significant impact on pressure communication between crestal gas/water injectors and flank oil producers at overall area and history period. When it comes to local area (well-by-well level) matching phase, independent fine tuning process of excess KH maps derived from two different high-permeability streaks allowed us to achieve good matching quality for pressure, water-cut and GOR, especially for multi-lateral completion wells where injection water/gas breakthrough was occurred at different timing at each horizontal branch. The permeability modification along with the geological concepts of various high-permeability streaks contributed to achieve reasonable quality of history matching without extreme and un-realistic adjustment of the permeability model.
Waterflooding in Giant Carbonate Reservoir; Successes and Challenges
Authors: Mahmood S. , Salazar P. , Zhao X. , Pointing M. , Sayed A.
Published: November 2017

Objectives/Scope

The Mishrif reservoir in the Rumaila field is one of the largest carbonate oil reservoir in the world. The reservoir exhibits heterogeneity from good grainstones to poor lagoonal mudstones, with the presence of thin high permeability layers containing vuggy porosity. Since 1973, the Mishrif Reservoir went through several production phases which indicated lack of pressure support. Line-drive waterflooding presented risks of bypassed oil, low sweep efficiency and high residual saturations due to reservoir heterogeneity leading to low recovery.

Methods, Procedures, Process

The reservoir development has been modified from a line-drive towards a progressive pattern-flood to mitigate key uncertainties and risks for improved oil recovery. After a field trial, large scale water injection in the North of the reservoir began in 2014. This is achieved by utilizing existing infrastructure, converting some existing Producers to Injectors and carefully reactivating existing well-stock following the water injection response. A drilling campaign is planned to complete the inverted 9 Spot pattern, combined with the gradual upgrading of existing facilities. This will be followed by a 5-Spot pattern depending upon drainage and sweep performance.

Results, Observations, Conclusions

The results to-date are promising with a successful ramp up of production from ~150mbd to +400mbd from +200 active wells while successfully maintaining reservoir pressure above saturation pressure with current water injection of over 400mbd. In order to optimise the full field development and effectively mitigate by-passed oil and poor sweep efficiency risks, the sweep patterns must be properly understood across the various reservoir layers and areas. As the production and injection ramp-up continues, water injection priority is being continuously optimized along with reservoir surveillance with specific focus on monitoring reservoir pressure and water-cut trends in the producers to understand sweep and drainage across this giant reservoir. This will need to be complemented with the well conformance through a well thought out completion strategy and effective water shut-offs. The development plan is estimated to achieve an aerial sweep efficiency of ~75% in the most developed water flood patterns by 2035.

Novel/Additive Information

In addition to the production ramp-up, progressing pattern-flood and waterflood management, future development options are being evaluated. This involves fully utilizing learnings from the reservoir performance to-date and further developing deeper understanding of this world-class carbonate reservoir using new technology to further enhance production and recovery in more challenging reservoir quality areas.
The ALBION Project: An Observatory in the Heart of a Carbonate Reservoir
Authors: Massonnat Gérard J. , Rolando Jean-Paul , Danquigny Charles
Published: November 2017

The ALBION project applies a new and disruptive methodology of reservoir characterisation to the carbonate Urgonian Formation (South-East France) considered as the very best analogue of Mid Cretaceous reservoirs from Middle East. Thanks to numerous field sections and outcrops descriptions, to tens of wells drilled in the reservoir, to kilometres of cores, to monitoring of groundwater dynamics such as decades of hydraulic observations at pretty much the only natural outlet of a major groundwater reservoir (Fontaine-de-Vaucluse spring) and to a unique underground laboratory (LSBB, about four kilometers in the heart of the reservoir), a multi-scale model is being built for reservoir purpose. Different observation sites with wells whose spacing ranges from 2 to 20 meters contribute to the assessment of together the matrix, the fractures and the karst flow behaviours. Through the building of an observatory in the heart of a reservoir, the ALBION project is delivering advanced concepts and methodologies to apply to industrial projects in Middle East carbonate fields.