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.
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.
Transverse fractures created from horizontal wells are a common choice in tight and shale gas reservoirs. Previous work has shown that proppant pack permeability reduction due to non-Darcy flow in a transverse fracture from a horizontal well causes significant reduction in the fracture performance when the gas formation permeability exceeds 0.5 md. There are other configurations and architectures such as aligning the well trajectory with the fracture, either by drilling horizontal wells in the direction that results in longitudinal fractures or by just sticking with drilling vertical wells. However, when drilling and fracturing costs are considered, productivity is not the only optimization consideration.
The field example illustrates a case when the apparent choice to use transverse fractures from horizontal wells proved to be suboptimal from the productivity perspective, but fundamental considering economics. Parametric studies for permeability ranging from 0.01 to 5 md illustrate the importance of economics in addition to physical performance. For similar reservoir characteristics, the optimum fractured well architecture varies considerably, and therefore an extensive reservoir engineering approach may be necessary beyond the well completions and/or current prejudices and inadequate understanding.
Capillary pressure might be ignored in high-permeability rocks, but it cannot be neglected in low-permeability rocks. To study the effect of capillary pressure on production performance in low-permeability oil wells or reservoirs, the formulas for calculating water cut and dimensionless total and oil productivity indices (PIs) were derived by considering capillary pressure. PI and water-cut data were computed using the new models with capillary pressure included. The results proved that PI increases with water cut in high-permeability rocks but decreases with the increase in water cut within a specific range in low-permeability rocks. Waterflooding experiments were then conducted in core samples with low and high permeabilities. The experimental waterflooding data demonstrated the same relationship between PI and water cut that was proved in the new PI model. Finally, the PI data were calculated using production data from oil wells, and the results were compared with the experimental data of the PI determined from coreflooding tests. The curves of PI vs. water cut, obtained from the production data of oil producers, were consistent with those inferred from waterflooding data in core samples. Note that the core plugs were sampled from the same oil wells. The new PI model was used to explain the difference in production performance between high- and low-permeability oil wells..
Van Baaren, Peter Michiel (WesternGeco) | May, Roger (WesternGeco) | Zarkhidze, Alexander (Schlumberger) | Morrison, David (WesternGeco) | Quigley, John (WesternGeco) | Al Qadi, Abdulla (Crescent Petroleum)
In this paper we describe an integrated design of the acquisition parameters for a 3D seismic survey in a difficult geological and logistical environment using an ultra-high channel count point receiver recording system, productivity enhancement techniques and incorporating advanced processing tools. Advances in acquisition hardware and techniques change the way seismic surveys are designed. These advances include continuous recording, faster computers that allow running more elaborate algorithms, and new methods such as surface wave methods to model and subtract aliased groundroll. These new tools require different input data and different sampling. How these advances influence the design process is illustrated using a case study for a 3D survey acquired in the 3rd quarter of 2011 located in the largely sand covered thrustbelt area of the United Arab Emirates.
The seismic data were acquired using a high productivity technique that uses time and distance rules coupled with integrated QC rules based on active spread criteria to maximize productivity and minimize cross-talk between the individual seismic sources. The initial data from the 3D survey shows that the proposed integrated 3D survey design is adequate for coherent noise attenuation, source cross-talk removal and building a near-surface model.
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.
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.
Heterogeneity and tightness of carbonate retrograde reservoirs are the main challenges to maintain gas well productivities. The degree of heterogeneity changes over the field and within well drainage areas where permeability decreases from few millidarcies to less than 0.2 md. Thorough studies have been conducted to exploit these tight reservoirs and not only focused on well performance, but have extended to assure enhancing and sustaining gas productivity through practical applications of technologies. The main objective of this paper is to assess the performance of Multi-Stage Fracturing (MSF) in horizontal wells that were drilled conventionally and did not meet gas deliverability expectation. This paper gives a detailed analysis of well performances, exploitation approaches, and successful implementation and optimal cases to utilize new completion technologies such as horizontal multi stage fracturing to revive low producing gas wells due to reservoir tightness. Placing the horizontal wellbore reference to the stress directions plays a major role in the success and effectiveness of fracturing in enhancing and sustaining productivity.
Several wells have been drilled in tight reservoirs, but could not achieve or sustain the target gas rate. Recently, two wells were geometrically sidetracked targeting the development intervals based on logs of the original hole and completed with MSF toward the minimum stress direction. Open hole logs showed a low porosity development similar of the vertical holes. However, after conducting multiple stages fracturing, both wells produced a sustainable rate of more than 25 MMSCFD that prompted to connecting them to gas plants. Placing these sidetracks in the minimum stress direction helped to create transverse fractures that connect to sweet spots and sustain gas production. This paper provides thorough guidelines for selecting optimal candidates for MSF based on reservoir heterogeneity, proper design and execution of fracturing. It also addresses various components that contributed to the success of both wells, such as reservoir development, workover pre-planning, geo-mechanics studies, drilling operations and real-time support, completion operations optimization and best-practices, and performance evaluation of other producers in the field. The paper also includes essential recommendations for development of tight gas reservoirs.
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.
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.