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Treatment evaluation leads to problem identification and to continuously improved treatments. The prime source of information on which to build an evaluation are the acid treatment report and the pressure and rate data during injection and falloff. Proper execution, quality control, and record keeping are prerequisites to the task of accurate evaluation. Evaluation of unsatisfactory treatments is essential to recommending changes in chemicals and/or treating techniques and procedures that will provide the best treatment for acidizing wells in the future. The most important measure of the treatment is the productivity of the well after treatment.
Introduction This chapter is organized to help perform acidizing on a well candidate in a logical step-by-step process and then select and execute an appropriate chemical treatment for the oil/gas well. The guidelines are practical in intent and avoid the more complicated acid reaction chemistries, although such investigations and the use of geochemical models are recommended for more complicated formations or reservoir conditions. Effective acidizing is guided by practical limits in volumes and types of acid and procedures so as to achieve an optimum removal of the formation damage around the wellbore. Most of this chapter is an outgrowth of field case studies and of concepts derived from experimental testing and research. Justification for the practices and recommendations proposed herein are contained in the referenced documents. The reader is referred to the author's previous papers on matrix acidizing for references published before 1990. Concepts and techniques presented have ...
Assessment of diversion performance is key to determining success of stimulation. Doubts remain, however, regarding the evaluation of diversion effectiveness. As diverter enters the formation, a hump in the surface pressure curve usually is expected. It then can be interpreted as supporting evidence for diversion. This, however, is a simplification of the fluid-diversion process. Such a hump may not be observed during a diversion stage even when the process is effective.
Sajer, Abdulaziz (Kuwait Oil Company) | Alsabee, Ali (Kuwait Oil Company) | Eldaoushy, Ahmad (Kuwait Oil Company) | Attia, Adel (Kuwait Oil Company) | Al-Sardi, Manayer (Kuwait Oil Company) | Al-Abdulmuhsen, Shouq (Kuwait Oil Company)
Abstract Maximizing oil recovery is a very challenging assignment to oilfield operators worldwide. This requires additional and continuous adoption of new technologies and best practices. Water flooding is one of the most reliable recovery technique and been used for many years around the world to pressure support to the reservoir and minimize the bypassed oil in depleted reservoirs with no aquifer support. This paper is presenting a case of well that was drilled and completed as a dumpflood well to provide pressure support to an oil-bearing zone that contributes most of the field's production. Dumping rates have showed poor performance due to near wellbore damage since completion. Many conventional stimulation trials were carried out with no sustained success. The well was selected for an advanced acid stimulation technique to improve the dumping rate by using the concept of Oscillating Fluid Injection. This process achieves deeper treatment penetration and more uniform fluid distribution. Root cause analysis, core analysis and well history have been used to optimize the job procedures and acid recipe to remove the suspected damage. The above-mentioned process treated the target zone with the same acid recipe that has been used in the previous conventional acid stimulation job. The results of this advanced process showed a significant improvement in well injectivity compared with previous acid stimulation techniques. The post treatment evaluation showed an increased dumping rate by two times. The increased flowing bottomhole pressures observed in the surrounding producing wells confirm the direct benefit of the improved injectivity and consequent pressure support. These promising indications have opened new production optimization opportunities in the nearby wells to add significant oil gain. This paper presents an unconventional method of acid stimulation technology in the improvement of injectivity in surface injection and dumpflood injectors compared with conventional techniques. This technology has opened new opportunities for improving the injectivity of the dumpflood wells, and go for full field implementation to maximize the oil recovery from depleted reservoir.
Ali Issa, Abdelkerim (Zakum Development Company) | Uematsu, Hiroshi (Zakum Development Company) | Bellah, Samir (Zakum Development Company) | Al-Farhan, Zahra A. (Zakum Development Company) | Al Hashemi, Mohamed A. (Zakum Development Company)
Abstract A mature offshore Abu Dhabi oil field produces from a heterogeneous carbonate limestone reservoir with an important column of bottom aquifer. The reservoir heterogeneity is characterized by presence of kurst filled with fine materials at top section, conductive faults, fractures, and significant variation of other rock properties. Most of the main faults cross from the top of the oil column all away down to the bottom of the aquifer. Meanwhile, the field development mainly consisted of horizontal producers targeting the upper section of oil column with peripheral deviated water injectors to sustain reservoir pressure. Generally, producers start with high initial oil rates, but the early decline is steep due to rapid water cut increase resulting into lower well head pressure. Production profiles from PLT combined with FMI indicate that production and water influxes are contributing mainly from the fractured sections of the horizontal drain or through conductive faults. In the meantime, important matrix segments of horizontal drains present very low or no contribution to production. As a solution, surface bull heading and targeted zonal stimulations were performed, which yielded mixed results. This paper focuses on the analysis of the latest targeted matrix segment stimulation results, which include candidate selection background, description of stimulation method and operations, pre and post stimulation production performance analysis, analysis of main factors affecting carbonate matrix stimulation, and a summary of findings with overall implication to carbonate reservoir matrix stimulation.
Al-Hajri, Nasser M. (Saudi Aramco) | Al-Ghamdi, Abdullah A. (Saudi Aramco) | Al-Subaie, Fehead M. (Saudi Aramco) | Mujaljil, Salih (Saudi Aramco) | Al-BenSaad, Zakareya R (Saudi Aramco) | Srivastava, Abhiroop (Schlumberger) | Ahmed, Danish (Schlumberger) | Aiman Kneina, Mohammed (Schlumberger) | Molero, Nestor (Schlumberger) | Barkat, Souhaibe (Schlumberger)
Abstract Horizontal carbonate reservoir stimulation has attracted considerable attention in the past decade as one of the major areas for development in matrix stimulation engineering. Modern technologies have enabled technically suitable interventions in extended and even mega-reach wells. In the Middle East especially, carbonate field development strategies have used mega-reach wells as the main technique in achieving the highest possible reservoir contact. In such a case, coiled tubing (CT) intervention becomes a necessity. With carbonate acidizing, since more than 50% of the matrix is soluble in acid, the objective is to bypass the damage and increase the productivity by creating new highly conductive channels called wormholes. The success of a treatment is a function of fluid penetration, acid reactivity, injection rate and diversion. To increase the success of the treatments, improvements have been made recently in injection rate and diversion using the latest technologies in CT intervention. The introduction of CT provides significant advantages in stimulation execution, yet imposes some challenges. Real-time downhole measurements using fiber optic telemetry have been used frequently to improve chemical diversion and fluid placement. However, pumping rates have been significantly limited to a maximum of 2.0 bbl/min when this technology is deployed. Extensive engineering work was invested in solving this challenge. The main objective was to obtain the optimum diversion using downhole “point” and distributed measurements without sacrificing the high injection rates. In response to this need, modifications to the existing downhole measurement system were introduced enabling pumping of rates beyond 5.0 bbl/min. The key focus of the redesign was the repackaging of the downhole tools as well as the telemetry link to surface, resulting in expansion of the operating envelope of the technology. Yard testing has been completed, and results have been encouraging. The solution has been piloted in the field, and a field case study showed remarkable injectivity improvement.
Kent, A.W.. W. ( ConocoPhillips ) | Burkhead, D.W.. W. ( ConocoPhillips ) | Burton, R.C.. C. ( ConocoPhillips ) | Furui, K.. ( ConocoPhillips ) | Actis, S.C.. C. ( ConocoPhillips ) | Bjornen, K.. ( ConocoPhillips ) | Constantine, J.J.. J. ( ConocoPhillips ) | Gilbert, W.W.. W. ( ConocoPhillips ) | Hodge, R.M.. M. ( ConocoPhillips ) | Ledlow, L.B.. B. ( ConocoPhillips ) | Nozaki, M.. ( ConocoPhillips ) | Vasshus, A.. ( ConocoPhillips ) | Zhang, T.. ( ConocoPhillips )
Summary This paper describes the design, testing, installation, and performance of the first fully completed well by use of an intelligent inner completion inside an uncemented liner with openhole packers for zonal isolation. The well-design concept evolved from technical challenges associated with completing long cased-and-cemented laterals in the mature Ekofisk waterflood. The term fully completed implies full reservoir access along the pay length for production and high-rate matrix acid stimulation by use of limited entry for fluid diversion within well segments. The paper covers the development and qualification of custom openhole 7⅝-in.-liner components that can handle high differential pressures and severe temperature fluctuations of 200°F; the marriage of this complex liner with a five-zone intelligent-completion system; and results from 1 year of system-integration testing. The paper also discusses the strategic placement of both mechanical openhole and inner-string packers based on caliper and drilling logs; challenges met and overcome during installation; and comprehensive downhole-gauge data that confirms the performance of each component before, during, and after the stimulation. The Ekofisk field waterflood began in 1987 and continues to date, exceeding expectations for improved oil recovery while mitigating reservoir compaction. As the waterflood matures, new wells are more often found partially water-swept. Limited infrastructure for lifting and handling the high water production has led to increased emphasis on isolating these water-swept intervals. Cased, cemented, and perforated completions have traditionally been used for this service. Effective placement of cement is challenging in horizontals 4,000–8,000 ft in length, where rotation of the liner is not possible and high effective-circulating densities limit rates during cementing. Wide variations in reservoir pore pressures, often in excess of 2,000-psi difference along the lateral, are typical of the Ekofisk chalk and compound the difficulties of cementing. As a result, a new method for zonal isolation has been developed to ensure the success of future infill-drilling campaigns. The design and careful planning that went into the fully completed openhole uncemented-liner strategy resulted in a successful field trial and has proved this solution to be an effective alternative to cemented reservoir liners in long horizontals where zonal isolation is critical. Use of the intelligent-well system (IWS) allowed offline acid stimulation without rig, coiled-tubing, or wireline intervention. What would have traditionally been a significant water producer, with three water-swept zones totaling nearly 2,000 ft across a 4,000-ft reservoir section, has turned out to be one of the best oil producers in the field, with nearly zero water cut. Production results show high productivity with highly negative acidized-completion skins. With large investments in intelligent completions to provide zone-specific inflow control and water shutoff, isolation outside the liner becomes much more important. Over recent years, the Ekofisk wells have illustrated the difficulty of achieving effective cement along lengthy reservoir targets. The openhole fully completed solution combining an accessorized uncemented liner with an inner intelligent-completion string will allow operators to push the limits in terms of lateral length while maintaining full control over producing and nonproducing zones.
Arukhe, James (Schlumberger) | Hanbzazah, Shadi (Schlumberger) | Ahmari, Abdulrahman (Schlumberger) | Al Ghamdi, Saleh (Schlumberger) | Yateem, Karam (Schlumberger) | Aramco, Saudi (Schlumberger) | Bal, Moustapha (Schlumberger) | Ahmed, Danish (Schlumberger) | Baez, Fernando (Schlumberger)
Abstract Field development costs have risen with oil price. A resulting challenge with Arab heavy oil development remains how to generate competitive advantages through deploying efficient technological innovations and making cost-effective solutions a crucial part of a firm's strategy for rigless interventions. With strict commitments to environmental protection, the need for operational excellence and several process improvements necessary to yield dividends in the form of safe project delivery and to overcome several technical difficulties is vital. The scope of the paper is to examine coiled tubing (CT) stimulation and logging technologies used in the timely project execution of one of Saudi Arabia's largest field developments to cost effectively enhance matrix stimulation success. Some of these solutions include technologies for CT reach, CT access for dual laterals, acid placement optimization, and treatment effectiveness monitoring. CT extended reach solutions comprised tapered CT strings designed for ultradeep wells, drag reducers, tractors, and vibrators. Technologies for CT access for dual laterals include a flow activated multilateral tool for CT matrix stimulation employing pressure variation telemetry with bottom hole pressure (BHP) and casing collar locator / gamma ray (CCL/GR) for high success lateral identification. To optimize acid placements, distributed temperature survey and pressure measurements are used to enhance diversion and acid placements. A blend of tools assisted to monitor, analyze, and adjust in real-time the reservoir and stimulation fluids interaction. Viscoelastic diverting acid is designed to viscosify in situ as the fluid spends on the reacted formation for chemical diversion in carbonates. The concentration of the diverter was optimized from 20% HCl to 15% HCl. A unique solution for monitoring treatment effectiveness evolved to include real time production logging using single strings for CT stimulation and real time profiling instead of memory logging. This solution required less equipment mobilization and no wireline unit. Intervention from 99 producers and injectors reveals operational and cost benefits from deploying technological solutions and justifies the degree to which each technology solution fits the overall field development strategy. The implications of deploying these solutions include reduction of well counts from the original estimates in this field development to offer manageable total field development costs.
Abstract The geologically complex Algyo field, discovered in 1965, is the largest hydrocarbon occurrence in Hungary, consisting of more than 40 oil-and-gas-bearing layers. The Ap-13, is one of the biggest reservoirs and encompasses a myriad of challenges: it is a depleted (180 bars reservoir pressure at 2400 m) layered dirty sandstone reservoir with a low permeability of approximately 15 mD, containing saturated oil. The 122°C temperature, complex mineralogy, poor consolidation, and a wide range of sources of potential formation damage make any stimulation a challenging and detailed process. Water injection is one the most commonly used exploitation method because of its favorable results. Sustained injection rate with delimited surface pressure is necessary to maintain the operational and economical advantages; however, formation damage severely impacts the injection trend. Conventional stimulation systems such as acid outside phase emulsion and regular mud acids have been used in the past on Algyo injector wells to improve injectivity by targeting the possible sources of damage such as iron compounds, calcite, hydrocarbons, clays, and sand; however, the effectiveness of these treatments has had a limited effective time frame of a few months, with suspected rock disintegration in the near-wellbore area. Through virtual geochemical simulation and laboratory testing, a novel chelating system was identified as the most suitable technology to efficiently stimulate the Ap-13 reservoir and overcome the inherent extreme conditions. Three injector wells were treated with this technology, and now, two years later, stable injection rates at optimum surface pressures are still maintained. These favorable results have widened the potential application of the technology to oil and gas wells, and laboratory testing has been optimized through virtual geochemical simulation. Furthermore, the operational risk of stimulation treatment is reduced where no cores are available, such as old wells, or when timing is a constraint, as in exploration wells. Introduction The economical exploitation of Algyo field posed challenges because of the individual behavior of its reservoirs, thin oil edges, and moderate pressure communication via the common aquifer. A detailed general exploitation plan based on water injection/reinjection was prepared at the end of the 1960s, and the method proved very suitable. Because of the depletion of the field, a sustained injection rate with delimited surface pressure is necessary to maintain the operational and economical advantages. These parameters are disrupted with the evolution of damage in the near wellbore. To diminish this detrimental effect, two actions are necessary. First, it is very important that the quality of the injected water is controlled since presence of iron components, as well as other damageinducing elements such as biomass, has been revealed on lab analyses. Second, when damage has impact on the injection trend, it is important to execute a matrix stimulation treatment. Among other challenges, the Hungarian fields are characterized by their mineralogical complexity and elevated temperature gradients. Algyo field (sandstone reservoirs of deltaic origin) is not an exception (Table 1) and shares the need for a thorough preparation to execute any matrix acidizing treatment. Because of the low amount of quartz, the first concern for a proper design is to avoid an aggressive fluid which, even though it imparts high rock dissolution (Table 2), may cause severe nearwellbore deconsolidation, which is increased by the relatively high temperature. Based on previous experience, it was determined that the potential damage is directly related to iron compounds, clays, calcite, and hydrocarbons. Conventional acid systems such as acid outside-phase emulsion and mud acid were historically used; however, a change from conventional matrix acidizing technology was considered because of the previously mentioned high reactivity as well as for the following reasons:Short longevity of matrix stimulation treatments (1~2 months) Emulsion and sludge-forming tendencies Need for an even and homogeneous stimulation Secondary and tertiary precipitation concerns Deployment simplicity and health, safety, and environment (HSE) advantages The use of a novel chelating-based technology (NCBT) was identified as the best option. The NCBT is designed to be pumped as a single fluid system instead of requiring sequential fluid stages, which are typical to conventional approaches, and has the extra benefit of reducing the risk originated by secondary and tertiary reactions (having precipitates such as CaF2, amorphous silica, and pH-sensitive minerals among others). The NCBT can be deployed in formations containing high clay and carbonate content as well as in iron and zeolite bearing sandstone formations; it also has the advantage of a more even stimulation with less risk of disintegration and reduced acid emulsion and sludge-forming tendencies.
Abstract World demand for energy is substantial and continues to grow. By 2020, it is expected that the world will need approximately 40% more energy than today, for a total of 300 million barrels of oil-equivalent energy every day. Meeting higher energy demands will require a portfolio of energy-generation options including but not limited to oil, natural gas, coal, nuclear, steam, hydro, biomass, solar and wind. New horizons are being explored. Wells are drilled in greater water depths. Drilling units are continually upgraded to target deeper hydrocarbon-bearing zones. Wellbore tubular metallurgy is continually upgraded. Drilling, completion and stimulation fluids are being developed for extreme temperature and pressure environments. As the preferred technology to enhance "oilfield" energy production, well stimulation has and will continue to have an important role in fulfilling the world's future energy needs. Well stimulation generally uses fluids to create or enlarge formation flow channels, thereby overcoming low permeability, as in "tight" formations, and formation damage, which can occur in any formation type. A common and very successful stimulation option, matrix acidizing, utilizes acids that react to remove mineral phases restricting flow. Depending on the formation and acid type, flow is increased by removing pore-plugging material; or by creating new or enlarged flow paths through the natural pore system of the rock. However, higher-temperature environments present a challenge to matrix acidizing effectiveness. High temperatures can negatively affect stimulation fluid properties and certain acid reactions. Thus, careful fluid choice and treatment designs are critical to successful high-temperature matrix acidizing. With proper fluid selection, design, and execution, matrix acidizing can be applied successfully to stimulate high-temperature oil & gas wells and geothermal wells. These types of wells have some common features, but they also have significant differences (e.g., completions, mineralogy, formation fluids and formation flow) that influence stimulation designs and fluid choices. This paper summarizes best practices for designing matrix acidizing treatments and choosing stimulation fluids for high-temperature oil & gas wells and geothermal wells. Included are case histories from Central America. Lessons learned about differences and commonalities between stimulation practices in these well types are also discussed. Introduction As today's rate of finding new reserves is lower than in previous decades, exploration has turned more to deeper basins. Deeper wells are typically hot (greater than 250º F, for example). Permeabilities are also often lower and occasionally are the result of a network of natural fissures. Offshore wells in the Gulf of Mexico are now reported to reach bottomhole temperatures of 500º F. Recently discovered gas fields offshore Brazil have bottomhole temperatures ranging from 350 to 400º F. Over the past years, great improvements in matrix acidizing have taken place, parallelling the developments in hydraulic fracturing. Provided that the forecasted production/injection results make economic sense, matrix acidizing is still simpler, often less risky, and more economic to implement than hydraulic fracturing. Sophisticated laboratory equipment, expertise, and well testing software can help the engineer diagnose production or injection damage effects and mechanisms - making it easier to select proper well candidates and optimize job design. Treatment placement is better ensured through the use of chemical or mechanical diversion methods and technologies, and placement tools (coiled tubing, straddle packers, etc.). On-site quality control is enabled by modern sensors, monitors and software, enabling the engineer to determine the evolution of skin with time, and radius of formation treated. Modern blending and pumping equipment have provided the means to mix acid continuously without the need for pre-blending fluids. This eliminates the need for mixing tanks on location, and enhancing safety on location .