C. Ferreira, Flavio (Schlumberger) | Stukan, Mikhail (Schlumberger) | Liang, Lin (Schlumberger) | Souza, Andre (Schlumberger) | Venkataramanan, Lalitha (Schlumberger) | Beletskaya, Anna (Schlumberger) | Dias, Daniel (Schlumberger) | Dantas da Silva, Marianna (Schlumberger)
Oil-water relative permeability and capillary pressure are key inputs for multiphase reservoir simulations. These data are significantly impacted by the wettability state in the reservoir and by the pore space characteristics of the rock. However, in the laboratory, there are several challenges related to the validation and interpretation of the special core analysis (SCAL) measurements. They are mostly associated with the core preservation or restoration processes and resulting wettability states. To improve dynamic reservoir rock typing (DRRT) process, a new model, describing the change of wettability fraction with depth in mixed-wet reservoirs, is proposed. The proposed model is based on solid physics describing the interactions between the rock grain surfaces and the fluids filling the pore space. First, the model considers the oil migration from the source rock into the originally water-wet reservoir and the corresponding capillary pressure rise, as the height above the free water level (HAFWL) is progressively increased. Then, oil-wet and water-wet fractions are estimated for different static reservoir rock types (SRRT) and different HAFWL, based on the wettability change potential of the rock-fluid system and oil-water capillary pressure curves. Additionally, mixed-wet capillary pressure and relative permeability curves are estimated for both oil displacing water (drainage) and water displacing oil (imbibition) processes, based on the estimated mixed-wet fractions and single-wet curves. We discussed the model assumptions and its parameters' uncertainties. We prepared a comprehensive sensitivity study on the impact of wettability variability with depth on oil recovery results. This study used a synthetic carbonate-reservoir simulation model, under waterflooding, by incorporating the concept of DRRT defined according to the different SRRT and estimated wettability fractions. The results showed a significant impact of wettability variability on oil in place and reserves estimates for waterflooding processes in typical complex, mixed-wet carbonate reservoirs, such as the ones found in the Brazilian Pre-Salt. We also discuss the potential impact of wettability change with depth on well logs like resistivity, nuclear magnetic resonance (NMR) and dielectric logs. The proposed reservoir wettability model and its corresponding DRRT workflow is relatively simple and widely applicable, and may significantly improve reservoir simulation and wettability uncertainty analysis. It also explicitly identifies the required wettability parameters to be obtained from laboratory experiments and well logs. Finally, the proposed model may be integrated with special core analysis, well logs and digital-rock analysis.
Lv, Mingsheng (Al Yasat Petroleum Operations Company Ltd) | Al Suwaidi, Saeed K. (Al Yasat Petroleum Operations Company Ltd) | Ji, Yingzhang (Al Yasat Petroleum Operations Company Ltd) | Swain, Ashis Shashanka Sekhar (Al Yasat Petroleum Operations Company Ltd) | Al Shehhi, Maryam (Al Yasat Petroleum Operations Company Ltd) | Luo, Beiwei (Al Yasat Petroleum Operations Company Ltd) | Mao, Demin (Al Yasat Petroleum Operations Company Ltd) | Jia, Minqiang (Al Yasat Petroleum Operations Company Ltd) | Zi, Douhong (Al Yasat Petroleum Operations Company Ltd) | Zhu, Jin (Al Yasat Petroleum Operations Company Ltd) | Ji, Yu (Al Yasat Petroleum Operations Company Ltd)
Western Abu Dhabi locates in the west of Rub Al Khali Basin, which is an intra-shelf basin during the Late Cretaceous. The Shilaif source, Mishrif reservoir and Tuwayil seal forms one of the Upper Cretaceous important petroleum systems in the western Abu Dhabi Onshore. However, less commercial discoveries have been achieved within Mishrif Formation during the past 60 years since the large scale structures were not developed in western Abu Dhabi and the stratigraphic traps have not been attracted attention.
This study aims to investigate the exploration potential of both Mishrif structural and stratigraphic traps. It provided detailed study on Shilaif source rock, Mishrif shoal/reef reservoir and Tuwayil seal capability. Oil-source rock correlation, reservoir predication and basin modeling have been carried out for building Mishrif hydrocarbon accumulation model by integration of samplings, wire loggings and 2D&3D seismic data. Shilaif Formation is composed of laminated, organic-rich, bioclastic and argillaceous lime-mudstones and its generated hydrocarbon migrated trending to high structures. Three progradational reefs/shoals in Mishrif Formation were deposited along the platform margin, which are characterized by high porosity and permeability. Tuwayil Formation consists of 10-15ft shale interbedding with tight sandstone, acting as the cap rock of Mishrif reservoirs.
Mishrif hydrocarbon accumulation mechanism has been summarized as a model of structural background controls on hydrocarbon migration trend and shoal/reef controls on hydrocarbon accumulation. It is consequently concluded that Mishrif reefs/shoals overlapping with structural background are the favorable exploration prospects, and oil charging is controlled by heterogeneity inside a reef/shoal, the higher porosity and permeability, the higher oil saturation. Two wells have been proposed based on the hydrocarbon accumulation model, and discovered a stratigraphic reservoir with high testing production. This discovery encourages a new idea for stratigraphic traps exploration, as well as implicates the great exploration potential in western Abu Dhabi.
Summary: Abrupt and large changes in the earth properties (velocities) can cause conversion of the compressional waves to converted mode energy. Such converted waves could be recorded on the towed streamer seismic data. If they are not identified and removed early they can mislead the interpretation. In this paper, we are showing the successful application of the converted wave attenuation (CWA) workflow on the seismic data from the Mediterranean See, Offshore Egypt. Data is acquired with latest broadband technique and went through several iterations of velocity model building. The presence of the strong converted waves has threatened to undermine velocity model building and interpretation effort. The benefit of presented workflow is that it identifies and models the converted energy pre-stack pre-migration, however the subtraction is done pre-stack post-migration. Post-imaging subtraction gives improved flexibility in signal protection and improvements in the S/N ratio, especially in the areas where the separation of the converted more and compressional energy is small. Presented workflow is universally applicable to any areas where the converted modes occur.
Haddad, Mohamed (ADNOC Offshore) | Rashed Al-Aleeli, Ahmed (ADNOC Offshore) | Toki, Takahiro (ADNOC Offshore) | Pratap Narayan Singh, Rudra (ADNOC Offshore) | Gumarov, Salamat (Schlumberger) | Benelkadi, Said (Schlumberger) | Bianco, Eduardo (Schlumberger) | Mitchel, Craig (Schlumberger) | Burton, Phil (Schlumberger)
Injection of drilling waste into subsurface formations proves to be an environmentally-friendly and cost-effective waste management method that complies with zero discharge requirements. It has now become the technology of choice in offshore Abu Dhabi.
The aim of cuttings reinjection (CRI) is to mitigate risks associated with subsurface waste injection and reduce cuttings processing time and cost. In order to meet these goals, a cuttings reinjection subsurface assurance methodology was developed to improve cuttings processing and continuously monitor drilling waste injection operations.
Preparing for CRI operations required extensive drilling cuttings slurry testing to minimize processing time and develop optimum particle size distribution to reduce cost and increase the injected waste volume. The improvements were accompanied by downhole pressure and temperature monitoring of the injection well, thus facilitating analysis of injection pressures. Fracture containment was verified through a combination of pressure decline analysis, periodic injectivity test, temperature survey, and periodic modelling for fracture waste domain mapping. A backup injection well was used also as an observation well to monitor the pressure signitures in the injection formation.
More than 1 million barrels of drill cuttings and associated drilling waste have been safely and successfully disposed of into a single injection zone of CRI well over three years of operations.
The cuttings reinjection subsurface assurance method optimizes grinded cuttings particle size distribution, detects and identifies potential risks to provide mitigation options to prolong the life of the injector.
The proactive subsurface injection monitoring-assurance program was built into the fit for purpose CRI injection procedure to continually avoid injecting any rejected hard material, improve and update the process as per subsurface injection pressure responses, thus reducing processing time and cost, mitigating injection risks, and extending the injection well life.
This paper presents the unique and technically challenging cuttings slurry properties design and pressure interpretation experience learned in this project; the enhancement of cuttings processing helped increase injection volumes and an in-depth interpretation of fracture behavior which behaved like a risk-prevention tool with mitigation options. Significant enhancement was developed in slurry treatment procedures to avoid injectivity loss and maximize the disposal capacity.
Azraii, Azraii Fikrie (PETRONAS CARIGALI SDN BHD) | Adhi, Adhi Naharindra (PETRONAS CARIGALI SDN BHD) | Hui Chie, Thian Hui Chie (PETRONAS CARIGALI SDN BHD) | Claire, Claire Chang (PETRONAS CARIGALI SDN BHD) | Ridzuan, Ridzuan Shaedin (PETRONAS CARIGALI SDN BHD) | Roh, Cheol Hwan (PETRONAS CARIGALI SDN BHD) | Zarir, M. Zarir Musa (PETRONAS CARIGALI SDN BHD) | Firdaus, Firdaus Bidi (HALLIBURTON)
Sarawak, Malaysia first offshore high rate dry gas field has an over pressured reservoir. Successful pressure control during drilling required the use of barite in the water based drilling mud in PMCD mode inside carbonate. Barite is very abrasive and is insoluble in any acid or solvent. Any barite left in the reservoir due to mud losses has to be produced back to surface after completing the wells. This cleanup is crucial for the safety and longevity of permanent facilities, especially when high rate gas wells are involved; due to the high rate of impact of any solids that may be produced with the gas. It is also critical to design the cleanup job carefully to ensure proper equipment and safety measures are taken to avoid washouts and related safety hazards.
To ensure solids free production from day one, a procedure was implemented and successfully executed during the development of this first offshore high rate high-pressure sour gas field. This was achieved by using the tender rig as a main support and complementing the safety with the incorporation of the selected well testing equipment management system. In addition to the proper equipment, a detailed cleanup procedure, which covered systematic production ramp up and defined solids free criteria, was implemented from well owner or asset. So far, this well cleanup setup and program has been implemented on several wells on platforms with minor erosion and no safety issues.
One platform with several wells is already producing and is flowing trouble free. This paper will describe the details of the setup of the rig facilities to clean these barite fluids from the wells, and the solids control equipment used and the cleanup procedure.
Iron Sulfide deposition in production facilities is one of the flow assurance issues in oil and gas industry. It can cause tubing blockage, interfere well intervention, and reduce production in both sour oil and gas wells. Mechanical descaling is currently applied, but it is time consuming and costly. Dissolvers based on concentrated hydrochloric (HCl) acid have high dissolving power, but with a limited applicability due to overwhelming drawbacks such as corrosion and H2S generation. Low corrosive, non-acid chemical dissolvers were developed. However, the dissolution rate is low and is not comparable to concentrated hydrochloric (HCl) acid performance.
Following the development of the iron sulfide dissolver presented in ADIPEC 2017, this work focuses on the improvement of the kinetics of iron sulfide dissolution, the kinetic factors of the dissolution rate. The non-acidic iron sulfide dissolver was used in lab dissolution tests. The effect of dissolution temperature, particle size, agitation, and ratio of volume of dissolver and mass of scale, were studied. Scale dissolution tests at temperature between 40°C and 125°C were carried out to evaluate the dissolution rate of pyrrhotite scale particles of sizes between 10 and 80 mesh. The ratios of volume (ml) of dissolver and scale particles (gram) were tested from 10:2 to 20:1. The agitation was from static to 160 rpm. The tests lasted for 6 hours. The dissolving amount was calculated by weight difference between the initial and final solids.
The results show that the kinetics of pyrrhotite dissolution can improve significantly at high temperature due to the increase in the thermodynamic of dissolution, and by reducing the particle size to increase the contact surface area of scale particles. The increase of volume ratio of dissolver with the mass of scale particles and increasing agitation have limited effect on the kinetics of scale dissolution under the test conditions.
This study provides and ranks the kinetic factors for iron sulfide dissolution. It gives a guideline to improve iron sulfide dissolution during field application using non-acid based iron sulfide scale dissolver.
The huge resources of unconventional hydrocarbon reserves across the world coupled with the growing oil value makes their contribution to be significantly important to the world economy. Oil producing companies can invest in unconventional hydrocarbon to cover local demand and save crude oil for exporting. Conversely, one of the foremost challenge that producers face in unconventional reservoirs is the need for large stimulated reservoir volume (SRV) to ensure economical production.
This study describes a new stimulation technique to increase the stimulated reservoir volume using the chemical reactions along with hydraulic fracturing fluid. Reactive chemicals are used to generate the localized pressure and heat in tight formations to create additional micro fracturing, thus increase the fracture complexity. Created induced micro-fractures considerably increased the porosity, permeability, and ultimately the SRV. The synthetic sweetspots are created nearby a wellbore and fractured area by the help of new stimulation treatment mechanism. Results showed significant conductivity increase with new treatment technique.
Rock samples were studied for mineralogical and microstructural characterizations using advanced spectroscopy and microscopy analytical techniques. Moreover, on each rock specimen ultrasonic compressional (P-wave) and shear (S-wave) velocities were recorded and dynamic Poisson's ratio and Young's modulus were determined. The obtained topographical images revealed the presence of micro-cracks and nanoscale pores in all studied core samples.
The novelty of this study is to develop a novel fracturing technique to increase stimulated reservoir volume (SRV). The parameters studied in this research can be served as critical inputs for many field applications such as wellbore stability, casing design and perforation, sand production control, and fracturing.
We are in an era where digital technologies are developing at exponential rates and transforming industries wholesale. The confluence of machine learning advances, accelerated growth in acquired data, on-demand CPU and GPU driven computing such as cloud infrastructure, and other advances in automation and robotics are causing an industrial revolution that some term as the "Fourth Industrial Revolution". Given that all these transformative technologies are now available and rapidly reinventing other industries, why is the rate of adoption in the oil and gas industry so slow? How can we best utilize these advances to stop drowning in data and instead transform this data into information and knowledge in order to enable secure and intelligent automation in oilfield operations?
The oil and gas industry has attempted, at times successfully, a multitude of big data and analytical techniques to further describe and analyze the systems’ or system of systems’ subsurface interactions. While the proofs of concepts have shown promise, structural difficulties embedded in the design of 20th century systems hinder the implementation of the methods and procedures now part and parcel of the 21st century, driven forth because of the Fourth Industrial Revolution. Unfortunately, 20th century procedures are not able to incorporate 21st century driven processes and methods of conducting business.
We outline some of the structural challenges facing the oil and gas industry and describe a few of the solutions that have been developed to help companies in the industry. These include applications from the subsurface in geophysics, completions design, and production. Overcoming data silos in traditional data infrastructure requires a novel approach to cloud infrastructure that respects user access, data privacy, and data residency requirements of companies. Assessing data for quality and for reasonable diversity and variation in order to answer questions posed by oil & gas companies can be quite profound. This critical step prevents companies from spending lots of non-productive time and money trying to develop and tune machine learning algorithms to produce answers that are simply not available in the data. Further, getting data to be in a form suitable to apply artificial intelligence can be quite involved.
We illustrate the above challenges by several subsurface examples and then describe the implementation of novel solutions. What we will show is that the oil and gas digital highway presently has data traffic jams preventing it from moving at the speed of light. Removing these traffic jams offers decision-makers the opportunity to move from insight to foresight – looking out in front instead of the rearview mirror to drive change.
Design of deepwater Subsea Control & Umbilical Systems is a challenging process subject. Challenges are emerging from subsea flow assurance ever demanding requirements as well as control and data transmission implications through long step-out. Zohr project Accelerated Start-up Phase FEED design adopted a Centre Control Platform (CCP) to accommodate the chemical injection, power & control Topsides facilities feeding and controlling subsea equipment at different drill centres through umbilical network. Subsea control is based on enabling multiplexed electrohydraulic Subsea Production Control System (SPCS) with Fiber Optic (FO) communication. Control of each drill centre is independent based on segregated power and data transmission scheme. The development adopted tight schedule due to the significance to country economics.
Chemical Injection and control with related data transmission through very long step-out umbilical has demonstrated to be a complex job in terms of assuring reliable connection of the CCP with subsea equipment located about 160km far away from the CCP. This complexity is merited to tight coupling between SPCS, umbilical system and installation engineering. Also, the heavy impact of failure downtime attributed to production loss along with increasing cost of intervention has significant footprint on every design aspect.
The current paper highlights a Fast-Track parallel design approach for very long step-out subsea development based on Zohr project achievements. With the tight schedule and massive amount of material involved in umbilical manufacturing (i.e. 2.2millions meter cables, 2million meter of tubes, and 2.7 million meter of fillers), any change after umbilical purchase order issuance will have significant impact on project execution and will probably put the project schedule into major risk. The traditional relay-based design scheme is replaced with an approach minimising the dependency of Umbilical Design on SPCS and Installation engineering.
The criticalities include impact of power distribution/sparing scheme on electrical cables configuration and design of Umbilical Termination Assembly. Also, the work covers FO link budget design challenges, need for midway repeater and related impact on connection design between main umbilical sections. The proposed approach is supported with conservative deployment scheme to eliminate installation risks.
Finally, the paper will conclude with a summary for key aspects to be taken into consideration during FEED in case of very-long step-out projects. Very-long step-out subsea field development projects being limited worldwide, the work will be valuable reference for similar future projects as being handling technicality from project management perspective.
Shiwang, Rahul (Baker Hughes, a GE company) | Chandrashekar, Telu (Oil & Natural Gas Corporation Ltd.) | Banerjee, Anirban (Baker Hughes, a GE company) | Chakraborty, Srimanta (Baker Hughes, a GE company) | Telang, Viraj (Baker Hughes, a GE company) | Deshpande, Chandrashekhar (Baker Hughes, a GE company) | Malik, Sonia (Baker Hughes, a GE company)
A number of exploratory wells were drilled in Eastern Offshore of India, encountering thick turbiditic sequences. The formation evaluation through conventional logging tools is a challenge in such depositional environments as the tools are unable to resolve thin beds and provides a weighted average log response over a collection of beds. In such environments, often the potential pay intervals are overlooked if comprehensive petrophysical analysis is not carried out. While the thin bed problem underestimates the reservoir potential, the orientation of measurement of the petrophysical properties further complicates the problem due to formation anisotropy. Another important characteristic of layered thin bed sand shale sequence is the acoustic anisotropy due to the transversely isotropic nature of sedimentary deposition.
The multicomponent induction tool was logged in the study area, providing a tensor measurement of the horizontal (Rh) and vertical (Rv) components of resistivity. The well encountered thick turbidite sequence of laminated pay sands with very low resistivity contrast. The initial stochastic petrophysical analysis from conventional open hole log responses indicated poor reservoir quality with high water saturation. Integration of high-resolution acoustic data and VTI analysis with multicomponent induction tool shows a clear evidence of alternating shale and sand sequences in the target reservoir. A high-resolution processed acoustic porosity was incorporated to build the lithology model with multicomponent resistivity data. Integration of ResH, ResV and VTI into a Thomas-Stieber petrophysical model indicates potential hydrocarbon bearing sands at two depths which were further included to optimise the formation testing and sampling plan.
During fluid sampling at the two identified depths, 54 and 157 ltrs. of fluid volume was pumped out before collecting samples by utilizing real time downhole fluid identification technologies. Optical absorbance and refractive indices were used to differentiate between miscible fluids. Clean-up from SOBM to formation oil was monitored using trends in representative channels of constantly changing absorbance spectrum. The formation testing results, therefore, were in good agreement with the identified pay intervals from the T-S model. Furthermore, Stoneley permeability analysis were carried out in the study area and calibrated with formation testing results. In the absence of imager data in the example well, formation dip was computed based on the multicomponent induction tool, which provided a close match to the OBM imagers, which struggled due to low formation resistivity, logged in adjacent wells.
This paper highlights the integrated workflow of multicomponent resistivity data based Thomas Stieber petrophysical model with high resolution acoustic and formation tester results of the example well and its success in delineation of pay sand intervals.