Offshore production of heavy oil can be challenging due largely to adverse fluid properties, sand production and flow assurance concerns. Recent technology advancements effectively driving management of these challenges and government support through tax relief have significantly contributed to the increased appraisal activity over the last several years in the North Sea heavy oil fields. Application of appropriate technologies and techniques has always been of paramount importance for acquiring high quality information throughout welltest for reservoir characterization at appraisal stage of the fields. It also provides high level of confidence in technology and "proof of concept?? prior to further application in a full field development at investment intensive offshore operating environment.
This paper describes an integrated approach in analytical modeling and design developed and applied in the planning of flow test in a number of North Sea heavy oil fields. This includes a comprehensive pre-evaluation of well productivity, PVT properties modeling as well as design and selection of appropriate artificial lift method. A series of technical solutions considered relevant in relation to enhancing the low flowing well head temperature conditions, typically observed during the cold heavy oil production offshore and often leading to operational constraints on fluid handling capabilities is also discussed. Additionally, a probablistic approach considering base case, low and high case scenarios has been developed and implemented as part of the evaluation process, given the limited amount of available information and high level of uncertainties.
The study demonstrates the benefits of applying analytical techniques for uncertainties handling during flow test planning and thereby enabling accentuation of potential issues, properly planning for mitigation actions and predicting the entire flow test sequence. Finally the study underlines some important guidelines pertaining to planning for further appraisal and development of new heavy oil fields.
Al-salali, Yousef Zaid (Kuwait Oil Company) | Ayyavoo, ManiMaran (Kuwait Oil Company) | Al-ibrahim, Abdullah Reda (Kuwait Oil Company) | Al-Bader, Haifa (Kuwait Oil Company) | Duggirala, Vidya Sagar (Kuwait Oil Company) | Subban, Packirisamy (Kuwait Oil Company)
This paper discusses the outstanding performance achieved in a deep HPHTJurassic formation drilled using Potassium Formate based fluid. This paper alsodescribes methodology adopted for short term testing and stimulation of anexploratory well and finally the field results.
Drilling and completion of deep Jurassic formations in the state of Kuwaitis generally done with Oil Base Mud (OBM) weighted with Barite. Duringdrilling, barite causes significant formation damage to the carbonates withnatural fractures and it is essential to stimulate the well to evaluate thereal reservoir potential. Formation damage is usually treated with matrix acidstimulation, however barite does not respond to acid. Kuwait Oil Company (KOC)was in search for an alternative drilling fluid causing relatively lessformation damage and also responds to remedial actions. Potassium Formate brinewith suitable weighting agent to achieve sufficient mud weight around 16ppg wasselected for field trial in one of the exploratory wells. Formate based brineis a high-density Water Base Mud (WBM) which maintains rheological stability athigh temperature and minimizes formation damage.
Last 2,000 feet in 6" hole section of 18,000 feet well was drilled using15.9 ppg Potassium Formate WBM. During short term testing, acid wash alone wassufficient to remove the formation damage and productivity has tripled which isunlikely in case of wells drilled with OBM.
This case study shows how Potassium Formate based mud enhanced theproductivity and reduced the testing time and cost. Based on the successfulfield test results, it is planned to drill future Jurassic deep formation withPotassium Formate based fluids in future.
The well drainage pressure and radius are key parameters of real-time well and reservoir performance optimization, well test design and new wells' location identification. Currently, the primary method of estimating the well drainage radius is buildup tests and their subsequent well test analysis. Such buildup tests are conducted using wireline-run quartz gauges for an extended well shut-in period resulting in deferred production and risky operations.
A calculation method for predicting well/reservoir drainage pressure and radius is proposed based on single-downhole pressure gauge, flowing well parameters and PVT data. The proposed method uses a simple approach and applies established well testing equations on the flowing pressure and rates of a well to estimate its drainage parameters. This method of estimation is therefore not only desirable, but also necessary to eliminate shutting-in producing wells for extended periods; in addition to avoiding the cost and risk associated with the wireline operations. The results of this calculation method has been confirmed against measured downhole, shut-in pressure using wireline run gauges as well as dual gauge completed wells in addition to estimated well parameters from buildup tests.
This paper covers the procedure of the real-time estimation of the well/reservoir drainage pressure and radius in addition to an error estimation method between the measured and calculated parameters. Furthermore, the paper shows the value, applicability and validity of this technique through multiple examples.
Transient linear flow diagnostic plots in shale gas wells often exhibit a positive y-intercept and may mask the early transient linear flow regimes because of non-reservoir pressure drops. Increased completion resistance reduces the peak production rate early in the life of a well impacting NPV. The shale gas industry is very early in the research required to distinguish the individual contributions of completion resistance, e.g. poor fracture conductivity, near-perforation damage or choke skin, and fracture face damage skin. Many of these phenomena can be diagnosed in production wells using unique shape(s) from various diagnostic plots allowing for analysis of completion effectiveness.
Mechanistic reservoir simulations were used to generate diagnostic plot signatures for low conductivity fractures, choke skin, and near fracture face damage. Subsequently, the corresponding signatures were compared with a large database of shale gas wells in numerous plays across North America to aid in the fingerprinting of these non-reservoir pressure losses. Only low fracture conductivity, not choke skin, can have a quarter slope. Near fracture face damage results in two distinguishable linear trends, one of the damaged region and the other for the matrix.
Completion skin diagnosis is a way of evaluating fracture efficiency by identifying the root causes of the non-reservoir pressure losses so as to mitigate them in the future. The following presents a catalogue of signatures that enables greater diagnostic capabilities to classify non-reservoir pressure losses. The study is the first comprehensive cause-by-cause look at completion damages with an emphasis on identification and diagnosis in shale gas wells.
It is fundamental to pilot and deploy IOR/EOR initiatives to improve recovery from petroleum reservoirs using cost effective methods, ensuring a continuous supply of production that would meet the ever-increasing demand for energy.
Under-Balanced Drilling (UBD) technology proved worthy as a valuable initiative in the redevelopment strategy of a Giant Carbonate reservoir located in the Middle East. It improved well deliverability especially in low permeability reservoir zones. The strategy for this has been to deploy 3-4000 feet laterals to maximize reservoir contact to such tight units or drill as far as possible to have maximum flow input/productivity. Horizontalization (non-UBD), together with stimulation has been going on for many years with mixed success as recent production log surveys showed negligible contribution from several wells completed in these low permeability units.
In 2011, well-X was drilled underbalanced to assess the value of this technology in augmenting productivity and improving reservoir characterization. Significant improvement in Productivity Index was accomplished by minimizing damage from drilling and completion operations. In addition, considerable knowledge was acquired from Flowing While Drilling (FWD) data and multi-rate tests in four segments of the production zone. Real-time geosteering was actively used to account for changes in the reservoir architecture.
Analysis of the FWD data has derived in new understanding of the dynamic nature of the reservoir's South-central region, highlighting sectors of high permeability, fractures, tight areas, different pressure regimes and varying fluid composition. Furthermore, despite the innovative nature of the technology, drilling and completion was very well controlled by the Well Construction teams, resulting in costs not significantly higher than normal over-balanced wells.
The enhanced reservoir knowledge that UBD delivers as shown from well-X will result in improved recovery efficiency and possible delayed water production. Moreover, it is a lead value improvement technology that will meet strategic business objectives with minimum risk and lowest Unit Technical Cost.
As the demand for gas increases worldwide, tight and deep unconventional gas sands are becoming the target for development. Continuous progress in hydraulic fracturing technology has resulted in multistage transverse fracturing of horizontal well in tight gas sands. However, for such reservoirs the conventional approach of simply fracturing the formation to stimulate the horizontal well is inadequate. This is because most currently available commercial software lack proper optimization tools in them and they do not take into consideration several key parameters and realistic constraints. Even the systematic design methods for fracture treatment parameters with constraints are not well presented in the literature. Although larger the number of transverse fractures higher the productivity, there are optimal number of fractures and optimum treatment parameters when real field constraints and economic aspects are considered. A new integrated but constrained model to optimize multistage transverse fractures has been developed to maximize gas production and net present value with minimum treatment cost. Model couples both the industry experience and unified fracturing design parameters based on hydraulic fracture mechanics. Unified fracturing design defines the optimal compromise between the fracture width and fracture length for a given mass of proppant. Model integrates unified fracture geometry, reservoir in-situ parameters, treatment parameters controllable at every stage, realistic design constraints, and production and economic modules. The integrated model has been successfully applied to a hypothetical deeper and tight gas sands to demonstrate its merits. A simple and accurate analytical approach has been used for evaluating and optimizing the productivity. This model could also be used to study the potential of the deep UAE offshore tight gas sands, which is yet to be developed.
In shutdowns and turnarounds there are three groups interacting together during the event. The operation team (owners who get the equipment ready to work on), the mechanical maintenance team (typically made up of various contractors who perform the work) and the shared services team that support both of the above in getting their tasks completed, one of which is Safety Services.
Items such as, Breathing air delivery, gas detection/testing, confined space entry monitoring, high angle rescue and other constitute the main bulk of the shared safety services typically used on site during the shutdowns and turnarounds.
In most places, these services are thought of as extra requirement and as a cost center, although necessary and supported, safety isn't viewed as one of the productivity tools in a turnaround. They are typically left to the contractors to manage independently or in isolation creating redundancy in the amount of equipment available, incompatibility in the variety of brands and systems and duplication of efforts resulting in delays in tasks and a general poor perception of safety.
This paper demonstrates the effective use of a system of a a QA/QC process and a centralized distribution and dispatch for on site safety services such as Q-Cycle™, Resource Track™ and Site Courier™ of United Safety, in achieving safety goals as well as schedule productivity gains. This system and process can benefit both the owner/ operating companies as well as the general contractors as either or both can use it. It reviews an electronic method of tracking, reporting and data capture of the distribution and management of site safety services. Centralized distribution and dispatch system can manage daily needs as well as provide data for future planning.
In addition, the paper covers the case study and results of this system used in a large, major IOC turnaround; how the data benefited the operator and the mechanical contracting group as well as saved time and money through service quality and inventory management.
Successful Turnarounds and Shutdowns rely on Safety Performance, planning and efficiency. As costs are getting tighter, price of Oil is getting higher and in general the industry is getting busier, manpower availability is getting scarer and productivity becomes a critical compenent of a turnaround.
Pre-job requirements are increasing affecting job start times (Mobilization, permitting, pre job meetings, Critical Task Analysis, etc.). In addition, Blast zone protection coverage has extended the proximity (distance) of support services from the task location. (Tool cribs, consumable cribs and general warehouse) therefore Maximizing "Tool Time?? is more important than ever!
It is achieved through a proper implementation of a QA/AC process and Centralized Dispatch/Delivery of Safety services.
Ocean Bottom Cable (OBC) seismic survey has several technical advantages over conventional towed streamer technique. However, its usage is still limited as requirement of relatively large operational efforts likely results in more survey cost and duration. Moreover, OBC seismic operations could affect other field activities and multi-vessel operations required for OBC survey and longer survey duration potentially increase HSE risks in fields.
Consequently, enhancement and optimization of OBC survey productivity is essential particularly in specific situations such as shallow water, congested producing oil/ gas fields (e.g. Offshore Abu Dhabi) and in environmentally restricted areas.
Although several studies have been carried out to establish key parameters, designs and geometries for high OBC survey productivity, the current developments in the seismic industry technology and equipment are enabling to establish a variety of survey designs and geometries which were not feasible previously. Therefore, our study was conducted with the aim to analyze the impact of OBC Survey Designs / Geometries on productivity considering the current available equipment and technology and meeting the established geophysical survey objectives.
Applications of dual source operations were also discussed by using two cases: (1) Distanced Separated Simultaneous Shooting (DS3); and (2) Dual Source Vessel Flip-Flop Shooting (DSVFFS). Dual source operations for both marine streamer and land cases have been well described whereas few examples of its applicability to OBC survey have been presented. In this paper, we described the impact of dual source operations on OBC survey efficiency and technical challenges determined from the relationship between OBC Survey Geometries/Designs and interference noise wave fields which have to be considered as more complex scenario than other types of surveys.
We believe that the established new approach will assist to acquire future OBC survey with high productivity and in a very cost effective manner.
Ladmia, Abdelhak (ADMA) | Al-Marri, Faisal (Abu Dhabi Marine Operating Co.) | Hussein, Mohamed AlSalam (Abu Dhabi Marine Operating Co.) | Al-Neaimi, Ahmed Khaleefa (Abu Dhabi Marine Operating Co.) | Khalil, Hassan Ibrahim (Abu Dhabi Marine Operating Co.) | Ibrahim, Mohamed Elsayed (Abu Dhabi Marine Operating Co.) | Santhanam, Kalakad S. (ADMA-OPCO) | Abu Chaker, Hicham (ADMA-OPCO) | Al-Sheikh, Hosny (ADMA-OPCO) | Moslem, Samaai (ADMA-OPCO) | Al Marasy, Hatem (Schlumberger) | Salasman, Alan
Several wells in Offshore field Abu Dhabi are unable to flow due to Low Well Head Flowing Pressure LWHFP and also other wells are unable to flow due to Asphaltenes deposit causing a restriction under certain conditions of pressure and temperature even after a remedial job using a mixture of Xylene-Diesel (20% / 80%). However the well in this case, Well-1, has a combined problem being unable to flow with both LWHFP & asphaltenes deposit.
In some applications the field layout and operation conditions also cause restrictions in production from the producing wells. The use of the technique of re- perforation using a 2'' Premium Deep Penetrating Gun plus additional acid stimulation with a coiled tubing unit CTU to remove formation damage through double casing is a cost effective way to lower the skin and boost the flowing pressure of LWHFP wells.
Remediation of LWHFP often requires a complex and time consuming intervention (Acid Fracturation, Side Track etc.) with relatively low success rate, which is perhaps why thousands of wells globally currently exhibit LWHFP and cannot be produced due to high line pressure (HPP) in the gathering pipelines.
The objective of this paper is to highlight the challenging yet successful techniques implemented to remediate restricted tubing due to asphaltenes precipitation and restore productivity in the off-shore Field, Abu Dhabi. These jobs are done rigless to aid efficiency and keep cost down and have been successful at getting the wells back on line.
Gas condensate reservoirs differ from dry gas reservoirs. Understanding of phase and fluid flow behavior relationships is essential if we want to make accurate engineering computations for gas condensate systems. Condensate dropout occurs in the reservoir as the pressure falls below the dew point, as a result of which, gas phase production decreases significantly.
The goal of this study is to understand the multiphase flow behavior in gas condensate reservoirs and, in particular, focusing on estimating gas condensate well deliverability. Our new method analytically generates inflow performance relationship (IPR) curves of gas condensate wells by incorporating the effect of condensate banking as the pressure near the wellbore drops below the dew point. The only information needed to generate the IPR is the rock relative permeability data and Constant Composition Expansion (CCE) experiment.
We have developed a concept of critical oil saturation near the wellbore by simulating both lean and rich condensate reservoirs and observed that the loss in productivity due to condensate accumulation can be closely tied to critical saturation. We are able to reasonably estimate re-evaporation of liquid accumulation by knowing the CCE data.
We validated our new method by comparing our analytical results with fine scale radial simulation model results. We demonstrated that our analytical tool can predict the IPR curve as a function of reservoir pressure. We also developed a method for generating an IPR curve by using field data and demonstrated its application by using field data. The method is easy to use and can be implemented quickly.