For steam injection parameters of greater than 700 psi and 500 deg F, a high production casing failure rate is often observed. This is due to severe thermal stress condition to the production casing string. The production casing may easily be in compression hot-yield under these conditions. This can lead to high casing failure risk in the forms of excessive deformation, buckling, and collapse. This paper presents an analysis on casing and cement stresses under the stated steam injection conditions. The interaction of casing-cement-formation is considered to help understand casing and cement failure mechanisms and potential approaches to reduce casing failures in cyclic steam frac wells. The loss of cement integrity and support to production casing string may occur under steam injection condition, which attributes to casing failures in the forms of excessive deformation, buckling, and collapse.
Field surveyed temperature in a cyclic steam frac well is also presented and compared with modeled casing temperatures to show the needs of correctly modeling casing temperatures. Recent casing design practices in some Bakersfield area cyclic steam frac projects, including the successful use of high strength grade casing such as P-110, are discussed in order to reduce casing failures in the cyclic steam frac wells.
Optimal completion design has been practiced over the past years through detailed well performance evaluation, and improved completion selection workflow. Six field case studies will be discussed in this paper to demonstrate the methodology to achieve the best completion design under different field and operating conditions. The focus of the field case studies covers well production prediction, well performance evaluation, optimum well length assessment, cost effective and production efficient completion strategy, skin
estimate from well production history, water/gas control, impact of casing integrity, and sensitivity assessment on reservoir permeability, mechanical skin, non-Darcy skin, flowing bottomhole pressure (BHP), original oil saturation, and so on. The wells to be discussed include single, dual lateral horizontal wells, and highly deviated wells. The produced fluids include oil and/or gas and water. The most
popular completion options, such as open hole, slotted liner, inflow control devices (ICD), intelligent well completions (DIACS), perforated cemented liner, wire wrapped screen or standalone screen, gravel pack, and frac pack, expandable sand screen, alternating standalone screen and blank pipe, etc, have been either applied and/or evaluated in the case studies.
Well completion plays a critical role in well design, and more importantly, the performance of the well in its entire life. With more and more advanced well completion options deployed in new wells, especially in the deep and ultra-deepwater environment, the cost and the impact of the well completion is too significant to be ignored. An appropriate well completion design would lead to reduced well cost, enhanced hydrocarbon production, minimized water breakthrough, but more importantly, improved well performance and ultimate
The major objective for this study is to share some lessons learned from the design and evaluation of well completion configurations in a number of field applications, including:
The strategy and workflow that should aid to achieve an efficient completion design in regard to both cost saving and production efficiency will be illustrated while discussing the case histories.
Completion optimization design is far from new. A significant number of papers have been published in the SPE literature, covering a variety of topics such as: completion design, well performance evaluation, completion improvement, completion failure diagnostics, completion challenges, potential cost saving, and so on. Selected papers on the topics mentioned above are briefly introduced below.
To select bridging agents properly is a critical factor in designing the no-damaging or low-damaging drill-in fluids. Historically, the Abrams's rule has been used for this purpose. According to this rule, the median particle size of a bridging agent should be equal to or slightly greater than 1/3 of the mean pore size for a given target formation. However, Abrams' rule only addresses the size of particle required to initiate a bridge. The rule does not give optimum size or address an ideal packing sequence for minimizing fluid invasion and optimizing sealing.
This paper elaborates an ideal packing approach to solve the sealing problem, with the aim being to minimize formation damage by sealing pores with different size, especially those large pores which usually make dominant contribution to permeability and thereby preventing the solids and filtrate of drill-in fluids from invading into formations more effectively, compared with the conventionally used techniques.
A practical software has been developed to optimize the blending proportion of several bridging agents, so as to achieve ideal packing effectiveness. It is very convenient for use in the field only by inputting some data of formation, such as the maximum pore size or permeability.
It has been confirmed from numerous experimental results that the core sample contaminated by the drill-in fluid designed following ideal packing approach can acquire higher return permeabilities, and have a shallower invading depth, a lower breakthrough pressure as well as a lower dynamic filtration rate than cores contaminated by the drill-in fluid designed applying the Abrams's rule.
The method and its use in selecting the best blending proportion of several bridging agents, focusing on an ideal packing sequence for minimizing fluid invasion, are also discussed in this paper. A carefully designed drill-in fluid using the ideal paking technique (named the IPT fluid) for offshore drilling operations at the Weizhou oilfield located in the west of South China Sea is presented. The near 100% return permeabilities from the dynamic damage tests using reservoir cores prove the excellent bridging effect can be provided by this drill-in fluid.
Cui, Mingyue (Research Inst. of Expl./Devel.) | Shan, Wenwen (Langfang Branch of RIPED) | Jin, Liang (Shell E&P Asia Pacific) | Ding, Yansheng (Institute of mechanics, IMECH) | Ding, Yunhong (Langfang Branch of RIPED) | Chen, Li (Institute of Mechanics, IMECH) | Liu, Ping (Langfang Branch of RIPED) | Xu, Zhihe (PetroChina Co. Ltd.)
Low permeability reservoirs take a large portion of the newly discovered hydrocarbon reservoirs. Stimulating low and ultra low permeability reservoirs faces more technical challenges.
Unlike other stimulation techniques such as "well shooting??, "nuclear explosion??, and "high energy fracturing??, the concept of in fracture explosion (IFE) is to create a fracture hydraulically, convey solid explosives deep into the fracture and place them in the fracture. Then ignite the explosives in the fracture to generate crushed zones or shear fractures near the main fracture while keeping the well bore intact. In such a way, the well productivity is increased. For complex tight gas reservoirs, especially those that tend to develop multi fractures and shear fractures by conventional hydraulic fracturing making the placement of proppant difficult, this technology has irreplaceable advantage.
Fracturing fluid for in fracture explosion has two functions - to carry solid explosives while create hydraulic fractures, and to propagate ignition. This study has found such a fluid system that can meet both general requirements for hydraulic fracturing fluid and the realization of lighting, transmit fire, ignition, and propagate explosion under simulated reservoir conditions.
The fluid system was tested successfully in a narrow fracture simulator. Expected explosion realized in this simulation. The simulated fracture has a length of 2300 mm with variable width of 0-50 mm. The process of squeezing, igniting, and explosion of 300g TNT equivalent was tested.
This fluid system has the following properties:
Rheology at reservoir temperature can be adjusted according specific requirement. Viscosity ranges from 10 to 50 mPa.s. Wall building leak off coefficient is 3.6x10-4 m/min0.5 and spurt loss is 0.25 ml/cm2. Combined with a regular fracturing fluid as a lead (pad), such properties allow the fluid to satisfy the requirements of generating deep fractures and transport/place explosives in the fractures.
This paper will provide details of the study and discuss the potential applications for tight gas reservoir stimulation.
Hydraulic fractures are usually simplified as ones with double-wing, symmetric geometry. Recent study of off-balance growth of fractures1-4 indicates that for some reservoirs, acid and hydraulic fractures have extremely complex shapes. For some of the difficult reservoirs, due to the characteristics of the formation and rock mechanic behavior, it is impossible to place proppant in the fractures generated hydraulically. Certain effort should be paid to optimize the treating fluids.
Multiple Fracture Diagnostic and Its Effect on Optimum Design of Stimulation Fluids
During real stimulation operations, it is very often to see high treating pressures. Factors that cause high fracturing pressures include:
Dahlan, Mohammad Shaufi (Petronas Carigali) | Karim, Rahimah A. (Petronas Carigali) | Nordin, Khairul A. (Petronas Carigali Sdn Bhd) | Noor, Harun M. (ExxonMobil Exploration & Production Malaysia EMEPMI)
Angsi is an integrated oil and gas development project in offshore east coast of Peninsular Malaysia. It is one of the biggest oil producers in Malaysia, contributing one-sixth of the total national daily oil production. During its planning and execution stages, the project has had many successes and positive outcomes. It has been recognized as the model of success for all domestic and international operations in PETRONAS Carigali Sdn. Bhd. (PCSB).
The uniqueness of achievements in Angsi project relies on the successfulness of integrating its people and technology. With the recent skyrocketing oil price, the trend has been to chase for additional reserves and maximize crude production, and make it happen by whatever means possible (new technologies, joint ventures, aggressive recruitments etc). However, many projects failed to achieve these targets, despite being equipped with niche and advanced technologies.
Angsi project has successfully overcome these obstacles. The secret relies in the six key elements that have been nurtured in the working culture of every team member, which are; people, focus, integrated approach, planning, communication and feedback loop. With this unique culture, it has allowed the team to achieve major successes over the past 5 years.
Among those is the successful implementation of the largest platform-based hydraulic fracturing program worldwide, and first in Malaysia. This allows the development 0.5 TCF gas from the otherwise uneconomic tight gas reservoir. The team also managed to increase its reserves level 2.5 times from its initial size. Consequently, it increases Angsi's daily production rate from 65 to 115 kbpd. Finally, Angsi project successfully reduces its unit development cost (UDC) by 67%, lowering it from 5.1 USD/boe to 1.7 USD/boe.
This paper discusses how the six key elements have contributed to the successes of Angsi Field Development Project.
The Angsi field is located in the Malay Basin, about 106 miles off the East Coast of Peninsular Malaysia in a water depth of 230ft (Figure 1). It is the largest integrated oil and gas development in Malaysia1, with four drilling platforms and one production platform. Angsi is a joint venture development between PCSB and ExxonMobil Exploration & Production Malaysia (EMEPMI), with the field being operated by PCSB. The major oil bearing reservoirs are the I-35 and I-68 sands, while the major gas bearing reservoirs are the I-1, I-85, I-100 and the tight K-group sands.
The development team comprises people from diverse background. They come from either PCSB or EMEPMI, being multinational, multicultural, with various range of skills and experience level. With this diversity, forming an integrated team within a cooperative environment is not an easy task. In addition, there were risks involved in developing the Angsi field, considering the high level of uncertainties during the initial stages of development. The field also requires the implementation of new technologies to optimise production and reduce development costs. These situations create a real challenge for the team, which is to integrate between the people and the technology, besides minimizing the risks.
Angsi team has formulated six key elements to overcome these challenges. These are; People, Focus, Integrated Approach, Planning, Communication and Feedback Loop (Figure 2). All these elements have been blended together and nurtured in the working culture of every team member. They play critical roles in realising many major achievements of the development project.
Bibi hakimeh field, one of the biggest Iranian fields tat has an important role in daily production of oil and gas, was discovered at 1961 by drilling well no. 1 and at 1964 the well starting producing oil. Stratigraphic thickness of this field is 400 meter that increases in northern direction. And it has relation with Bangestan formation. Bibi hakimeh field is an oil saturated field which has a pressure of 2263 psi and a temperature of 147*F at gas oil contact. Horizontal drilling techniques are applied for such "thin reservoir" which the vertical drilling depth is not enough.
This paper investigates the applicability of horizontal drilling technique in well #74 Bibi hakimeh field that there was a need to use the horizontal drilling techniques, but this technique didn't have very good results in this field and the most horizontal wells that were drilled in this field had an equal or lower production than vertical wells. This method has advantages and disadvantages that are explained in this paper. The flow rate of vertical and horizontal wells is almost the same, but with respect to the geological structures and low reservoir thickness there was a necessity to drill horizontally. In this study the advantages and problems which horizontal drilling is dealing with area described. In addition some good data from wells that drilled horizontally in this field are available.
Compared with conventional tubing fracturing, coiled tubing (CT) fracturing has several advantages. CT fracturing has become an effective stimulation technique for multi-zone oil and gas wells. CT fracturing is also attractive production enhancement method for multi-seam coalbed methane wells as well as wells with bypassed zones. The excessive frictional pressure loss through CT has been a concern for CT fracturing. CT strings have small diameter and this limits the cross-sectional area open to flow. Furthermore, the tubing curvature causes secondary flow and hence results in extra flow resistance. This increased friction pressure results in high surface pumping pressure. The maximum possible pump rate and sand concentration, therefore, have to be reduced. To properly design a CT fracturing job, it is, therefore, essential to be able to predict the frictional pressure loss through CT accurately.
This paper presents two correlations for the prediction of frictional pressure of fracturing slurries in coiled tubing. One is developed based on full-scale slurry flow tests with 1-1/2-in. coiled tubing and slurries prepared with 35 lb/Mgal guar gel. The extensive experiments were conducted at the full-scale coiled tubing flow test facility. The other correlation is derived from the Srinivasan's friction factor correlation of Newtonian fluid in coiled pipes. The Srinivasan correlation is modified for the non-Newtonian fluids and it further requires an inclusion of the relative slurry viscosities which have been thoroughly evaluated in this study. The proposed correlations have been verified with the experimental data and actual field CT fracturing data. Case studies of wells recently fractured using CT are provided to demonstrate the application of the correlations. The correlations will be useful to the CT engineers in their hydraulics design calculations.
Hydraulic fracturing through coiled tubing (CT) has become an effective stimulation technique for multi-zone oil and gas wells.- Hydraulic fracturing via CT is also an attractive production enhancement technique for mutely-seam coalbed methane wells. In CT hydraulic fracturing, proppant such as sand is conveyed through the continuous string of coiled tubing as transport conduit to the fracture in a formation. Compared with conventional tubing conveyed hydraulic fracturing, CT hydraulic fracturing has a number of advantages. In particular, CT provides the ability to quickly move in and out of the hole (or be quickly repositioned) when fracturing multiple zones in a single well. CT also provides the ability to fracture or accurately spot the treatment fluid to ensure complete coverage of the zones of interest when used in conjunction with appropriate bottomhole assembly tools such as straddle packers. This is particularly important for stimulation of multiple zones or bypassed zones or horizontal wellbores. At the end of the formation treating operation, CT can be used to remove any sand plugs used in the treating process, and to lift the well to be placed on production.
The excessive frictional pressure loss through CT has been a concern for CT fracturing operations. CT strings have small tubing diameter - small enough so that adequate tubing length can be spooled onto the coiled tubing reel. This limits the cross-sectional area open to flow. Furthermore, the tubing curvature causes secondary flow and hence results in extra flow resistance. Therefore, fluid frictional pressure losses in CT hydraulic fracturing are much higher than those associated with conventional tubing fracturing. This increased friction pressure results in much higher surface pressure at the injection rates required for hydraulic fracturing. This elevated surface pressure is one of the dominant factors that currently limit the application of coiled tubing fracturing. High surface pressure necessarily implies that fluid injection rates will have to be much smaller when compared to conventional fracturing and the maximum sand concentration has to be reduced since sand increases slurry fluid friction pressure.
To properly design a CT hydraulic fracturing job, it is therefore essential to understand the flow behavior of hydraulic fracturing slurry in coiled tubing string and be able to predict frictional pressure loss in CT accurately.
Wang, Yan (1st Oil Prod. Co. Daqing) | Wang, Demin (Daqing Oil Company) | Wan, Jun (1st Oil Prod. Co. Daqing) | Luo, Jiangtao (1st Oil Prod. Co. Daqing) | Zhong, Ping (1st Oil Production Company of DaQing Oil Field Ltd.) | Dong, Zhengyou (1st Oil Prod. Co. Daqing) | Liu, Yingzhi (1st Oil Prod. Co. Daqing)
With the prolonged time of development and increased interlayer pressure difference, there is numerous cement channeling problems between isolated zonal intervals in production and injection wells in Daqing Oilfield. The cement channeling problems, especially in long intervals, change the original layers developed and make the interlayer interference more severe. Furthermore, all kinds of chemical treatment methods that are used to remedy channeling cannot meet the needs of plugging long interval channeling wells in the field because of the disadvantages of complex process, high cost, low success rate, safety concerns, high risk and etc. Therefore, a new method has been developed specifically for plugging long interval high pressure channeling wells by cement curing with an overburden pressure and the results are encouraging.
Cement channeling problems have adversely affected the oil production of the oilfield. Although the operators have done a great deal of research in terms of channel plugging, the present techniques cannot meet the needs of channel plugging, particularly long interval channels.
The present chemical plugging methods can be divided into two kinds based on the plugging agents:
The first one is high strength plugging agents, which takes advantage of the characteristics that the plugging agent can be cured in a short time, so the channel plugging job can be completed before the high pressure fluids push the plugging agents out of channeling interval. Or under the conditions of ensuring safety, the tubing string is pulled out of the casing after the plugging agents completely cures. Because of its high risk and complexity of the process, the methods that utilize high strength plugging agents to plug channels are not suitable for long interval or multi-interval channel plugging.
The second type is low strength plugging agents. Although safe to apply, it is only suitable for water shutoff of high water cut formation. This method causes the reservoirs to be completely plugged and the production cannot be maintained. Therefore, this kind of plugging agent is neither suitable for channel plugging nor long interval channel plugging.
Furthermore, since the techniques are quite complicated, present chemical plugging methods can be only mastered by a few technical workers who have engaged in the research work for a long time, which greatly restricts the spreading and application of channel plugging techniques.
Analysis for Channel Cause and Technical Keys to Cement Pluging
During the original stage of well cementation, the cement slurry displaces the well bore slurry from the bottom to the top, resulting in the annular region out of the casing being completely filled with cement slurry. But cement slurry has a solidification process from its initial curing to final curing. The higher the solidification, the more difficult it is for the fluid column weight of the cement slurry to pass to the cement and the reservoirs. During this period, the cement slurry is under the conditions of zero pressure. Under such a circumstance, the fluid column weight cannot overcome the pressure from high pressure layers. Then fluid from high pressure zones will channel through the uncured cement slurry and flow into low pressure layers, the cement slurry is diluted and channels form (Seen as Figure 1).
In addition, for ordinary wells, the cement goes through a dilatation-shrink process during its curing and the shrinking ratio is up to 2% or so. The shrinking effect of the cement creates slight cracks between the cement and the casing and/or the formation, resulting in the cementation factor gradually declining with time during the period of one month after well cementation.
Before the cement slurry cures, high pressure layer fluids may channel into the slurry that will lead to the failure of the plug job. To solve this problem, an overburden pressure, which is higher than the formation static pressure and less than the formation fracture pressure, should always be put on the cement column during the curing time. Thus, the problem of cement returning back into the well bore ,which is caused by the high pressure of the formation (higher than the fluid column static pressure) before the cement cures and resulting in the failure of the pluging job, to be overcome.
A seismic trace is decomposed into a set of Ricker wavelets of different dominant frequencies and amplitudes. The seismic trace can then be accurately reconstructed with all the wavelets in the set of wavelets. With certain targeted objective in mind, a new seismic trace can be reconstructed with a selected subset of the wavelets. This reconstruction is found very effective in reservoir sand mapping and characterization. Some examples are demonstrated.
Flow assurance has been one of the major considerations in deep water completion design, where undesired heat loss from production tubing contributes to the formation of gas hydrates and causes the deposition of paraffin and asphaltene materials. Traditionally, controlling annular heat loss has been achieved with the injection of steam, the application of silicate foam, the pressurization of the annulus with inert gas, the use of gelled oil as an insulating packer fluid, and the use of vacuum insulated tubing (VIT). Each of these applications, however, has drawbacks due to either its working mechanism or higher cost associated with the technology.
To secure the insulation of the wellbore and to reduce heat transfer from the production tubing to the surrounding areas, various aqueous insulating fluid systems with superior thermal properties have been developed in recent years. Field applications of these fluids have demonstrated significant reduction in heat loss by reducing conduction and minimizing convection. These thermal insulating fluids have been implemented with great success in over 75 deepwater riser and packer applications in the Gulf of Mexico (GOM) over the last several years. Case histories have demonstrated that installation of these water-based insulating fluids is an effective alternative to conventional insulation options, and is becoming the preferred insulation method in many deepwater projects.
This paper will highlight the evolution of different insulating fluid systems and the field experience with each system. Proper testing methods relevant to oilfield flow assurance will be discussed and testing results for these fluids will be detailed. Field cases in the Gulf of Mexico (GOM) will be summarized and the effectiveness of these fluid systems will be demonstrated.
Deepwater oil and gas exploration and development in the Gulf of Mexico (GOM) has been a great success since oil industry took the first step in the middle of 1990s. By the end of 2004 production from the deepwater fields in the GOM grew to an estimated 3.9 billion cubic feet of natural gas per day and 953,000 barrels of oil per day which accounted for approximately 65% of the GOM oil production in 2004. The trend of exploration and development within the deepwater GOM shows no sign of diminishment, as evidenced by the 118 deepwater projects on production as of 20061. It has been forecasted the deepwater fields in the GOM would be producing nearly 2.0 million barrels per day in 2008.
As more multiphase hydrocarbons are produced from deepwater fields and transported for long distances, flow assurance becomes a more critical factor in the design stages of any oil and gas production system.
Flow assurance covers all issues related to the maintainance of the flow of oil and gas from reservoir to reception facilities. Being a multi-discipline activity, it involves the assessment of multiphase production systems and management of possible flow stoppages due to the formation and deposition of solids. Prediction or modeling, prevention, and redemption of the formation of gas hydrate, paraffin, asphaltene, and scale buildup within the production tubing and flow lines are essential requirements.
The temperature in deepwater is usually near 40oF, or 4.4oC, which can cause flow problems in riser and export pipeline through undesired heat loss from production tubing by forming and depositing gas hydrate, paraffin, and asphaltene materials. Therefore, effective control of annular heat loss is critical to keep pipelines free of solid accumulations.
History of Thermal Insulation in the oilfields
Understanding and manipulating the thermal environment of oilfield operations has been a concern for more than 40 years. The potential economic impact associated with these flow assurance issues has been magnified considerably especially for deepwater development.