Hadibeik, Hamid (UT Austin) | Proett, Mark (Halliburton) | Chen, Dingding (Halliburton) | Eyuboglu, Sami (Halliburton) | Torres-Verdin, Carlos (UT Austin) | Sepehrnoori, Kamy (University of Texas at Austin)
Testing in tight formations and unconventional reservoirs poses significant challenges when determining reservoir pressure. The primary difficulty in testing a low mobility formation is that a conventional pressure transient test cannot be applied because the buildup time required for pressure stability after a typical drawdown is excessively long. To reduce testing time, a new automated pulse test method has been developed.
The new pulse test method consists of a drawdown or injection followed by a short stabilization period. Then depending on the buildup response, a new drawdown or injection is performed followed by a short buildup. This sequence is repeated until the desired buildup stabilization is achieved and then a final extended shut-in period is used for analysis of formation properties such as pressure and mobility. The pressure stabilization time can be further reduced by implementing an adaptive pressure feedback in the system.
This new method uses sequential pressure responses and automated pressure pulses. The analysis of the final pressure yields a measurement in 0.5% range of the initial formation pressure while decreasing the wait time by a factor of 10 for a packer-type formation tester. Furthermore, the pressure measurements are analyzed to obtain reservoir permeability and storage.
The new method was tested on synthetic reservoir models and a field study. These demonstrated that the method permits a rapid appraisal of pressure measurement in comparison with conventional testing. Moreover, the implemented feedback system mitigates the supercharge effect.
The prediction of asphaltene precipitation is an important topic in petroleum industry. Reliable evaluation of the asphaltene stability requires representative samples and measurement using special high pressure equipment. Moreover, development project may involve many reservoirs with many different fluids. Even inside of a connected reservoir, the quality of the oil and the asphaltene can vary through a large scale and the investigation of each fluid in the representative conditions become very expensive and often impossible.
Many fast screening methods have been proposed so far. The De Boer's diagram is one of the most useful methods. However, it takes into account only the properties of the hydrocarbon phase without any investigation on the asphaltene fraction : this method gives always pessimistic prediction of the risk of asphaltene precipitation. Other methods, colloidal instability index for example, are not consistent enough to be used for flow assurance issue.
Based on some relevant solubility properties of the asphaltene fractions, a new and easy way for screening asphaltene instability is proposed. Using PVT properties of the live oil and an easy asphaltene characterization procedure, this method allow limiting advanced investigation only to fluids which present a real risk of precipitation. The asphaltene characterization can be performed on dead oil samples.
If a precipitation risk is stated, additional tests, performed on pressurized representative samples or taking into account reorganization of asphaltenes from different fluids, will help to define the severity of the risk. For mitigation, a test set-up has been developed: it allows evaluating the efficiency of chemical additives to prevent plugging under flow conditions of fluids above the asphaltene precipitation threshold. Depending on the crude oil, the severity of the precipitation conditions, and the nature of the additive, the blocking of the capillary tube can be delayed or prevented.
Excessive water production and unbalanced sweep in a water flooded reservoir can significantly impact oil production and increase water handling expenses, jeopardizing the overall economic recovery of hydrocarbon within the field. The objective of this paper is to provide a review of various integrated water management techniques successfully implemented in a carbonate field in Saudi Arabia, balanced under the critical monitoring eye of a systematic strategic surveillance program deployed to assess sweep efficiency across the field.
Complex networks of super permeable streaks and sub vertical fractures highly influencing fluid transport media within the subsurface characterize this carbonate reservoir. Understanding fluid flow mechanism in this heterogeneous gravity dominated reservoir is a predominant factor influencing the various approaches designed to manage water production in the field. The key management strategies that have been introduced are horizontal sidetracking of existing vertical wells at the top of reservoir, rigless water shut-off jobs and employing cyclic production mode for wells with very high water cut. In addition, Inflow Control Device (ICD) completion technology is being deployed within lateral sections that have encountered flow dominating geological features, such as fractures or super-K, providing a practical, innovative solution for an effective homogenized flow distribution along the lateral intervals. Collectively, these employed practices have been found successful in substantially reducing water production and improving oil recovery as supported by field data.
Concurrent with these water management strategies, sweep conformance and flood front movement are regularly monitored by conducting a rigorous Strategic Surveillance Master (SSM) plan across the whole field. The results from saturation and production profile logs confirm efficient vertical and areal sweep conformance and ensure the effectiveness of the integrated water management strategies employed in the field.
Monte Carlo simulations demonstrate that probabilistic models of hydrocarbon volumes should correlate the degree of porosity uncertainty to the productive volume of the reservoir. Assessments that fail to model the relationship between productive volume and porosity uncertainty may create unrealistic resource estimates and valuations.
The findings are applicable to conventional exploration prospects with significant uncertainty of productive reservoir volume, and to unconventional resource developments with high lateral variation in reservoir quality.
Probabilistic models of hydrocarbon volume include an estimate of porosity, defined by a probability density function such as a normal or lognormal distribution. The distribution models the uncertainty around the "average?? porosity within the field. If a field is small, the productive volume represents a limited sampling of the reservoir. There is a possibility that the average porosity within the productive reservoir may be very high or very low. If the field is large, there is a greater chance that a high porosity in one portion of the field will be offset by a small porosity in another portion of the field, resulting in a narrow range of uncertainty around the average porosity. Probabilistic models that do not decrease the porosity range as reservoir volume increases may generate results in which a high porosity is applied to a large reservoir volume, resulting in resource volumes and economic valuations that are unrealistically high.
The solution lies in the use of multiple-segment models. If each segment represents a stratigraphic layer, or a portion of the potential productive area, and each segment is assigned the wide range of porosity appropriate for a small field, then increasing the number of productive segments will decrease the range of overall average porosity.
This paper clarifies the definition of porosity uncertainty in probabilistic models, reveals a relationship between porosity uncertainty and reservoir volume, and presents a method that will result in more realistic resource estimates and valuations.
Drilling and completing reservoirs without inducing measureable skin damage is rare. Frequently, drilling fluids impact a reservoir's flow potential while drilling as the rock matrix is invaded by solids and chemicals designed to enhance drilling performance. Drilling fluid can also cause formation damage if they are not properly removed during the displacement phase. hese solids can migrate to the perforating zone and cause damage. Completion fluid designs governed by density for well
control also often contribute to skin damage. Hydrocarbon flow may be impeded by damage caused by residual drilling debris or incompatible completion and workover fluids, in-situ emulsions, water block, organic deposition, or oily residue.
Specialized surfactant systems have been developed to remediate near-wellbore damage caused by drilling and completion fluids, and damage induced by failed remediation attempts. The properties of these treatment systems include their ability to
solubilize oil and, due to a significant reduction in interfacial tension between the organic and aqueous phases, effectively diffuse through the damaged zone to free up flow-resistant obstructions. The inherent properties of these systems make them
ideal for removing induced formation damage as well as an excellent option for displacing synthetic or oil-based mud (S/OBM) from casing prior to the completion phase. In open-hole (OH) completions, specialized surfactant designs have proven very effective in removing S/OBM filter cake damage. In cased-hole (CH) completions, they have demonstrated a high degree of efficiency to clean damaged perforations.
This paper presents a technical overview of surfactant systems for OH and CH remediation operations. The testing to qualify these fluids for the removal of damage and field results are presented that show the efficacy of these specialized surfactant systems to remove damage caused by OBM filter cakes and other oily debris to improve hydrocarbon recovery while addressing the operational challenges associated with these jobs.
Accurate reserve estimates for unconventional shale gas reservoirs are critical to their economic assessment and field planning. Reserves are typically assessed with log and core measurements. Much of the log-derived information is validated with cuttings and core data. In particular, adsorption isotherms are measured in the laboratory and used to estimate ultimate recovery.
Accurate shale gas reserve estimations require a storage model that incorporates the physics of small scale, i.e., nanopores. This model is critical for the interpretation of log data and the prediction of long-term production and ultimate recovery. Current models partition gas into two parts: gas adsorbed on the pore surface with density comparable to liquid and free gas in the shale rock pores and natural fractures. Such a storage model, however, fails to consider the extremely favorable conditions for capillary condensation in the kerogen-rich rocks: pores in the kerogen range from a few nanometers to a few hundred nanometers and the pore surfaces are strongly oil wet. These two conditions are highly favorable for capillary condensation to occur; consequently, a significant amount of hydrocarbon probably exists in kerogen pores in the liquid state. Capillary condensation in shale gas core plugs has been verified in a laboratory study and significantly more hydrocarbons were observed than one would have expected in a traditional model that does not include capillary condensation.
We propose a new shale gas storage model for organic-rich shale rocks that accounts for capillary condensation. In this model part of the ‘gas' exists in liquid phase inside kerogen pores. Capillary condensation is easy to model for single-component hydrocarbons. Under reservoir conditions, the hydrocarbons are usually a mixture of multiple components. This paper presents the method and theoretical result for estimating the total hydrocarbon volume for hydrocarbon mixtures in organic rich shales in the presence of capillary condensation.
Multiphase flowmeters (MPFMs) available today are mostly based on a combination of differential pressure measurement, provided by at least one flow constriction, such as a Venturi device, with phase holdup measurement based on nuclear techniques, electromagnetic techniques, or both. This paper investigates the issues of combining the ultrasonic Doppler velocity measurement with the differential pressure measurement for multiphase flow metering. The intention is to measure at least one "useful?? velocity of the flow, such as the bulk liquid velocity or the homogeneous mixture velocity, which can then be combined with a measured differential pressure across a "constriction?? device, such as a Venturi, to derive parameters needed to calculate liquid and gas flow rates. An ultrasonic Doppler velocity sensor has been tested in combination with a Venturi under multiphase flow conditions. The results show that, due to the effect of gas bubbles in the liquid phase, the interrogation depth of the ultrasonic wave is often limited to a shallow liquid region near the pipe wall. As a result, the ultrasonic Doppler sensor can measure neither the bulk liquid velocity nor the homogeneous velocity reliably. It is generally difficult to interpret the measured Doppler velocity and to derive the flow rates of a multiphase flow without employing an elaborate flow model. This work was part of a project co-funded by the UK Technology Strategy Board1, with industry partners The University of Manchester, Schlumberger Gould Research, and TUV-NEL.
Sutton, J. T. (Esso Australia Pty Ltd) | Glenton, P. N. (Esso Australia Pty Ltd) | Fittall, M. E. (Esso Australia Pty Ltd) | Moore, M. A. (Esso Australia Pty Ltd) | Box, D. (ExxonMobil Upstream Research Company)
The offshore Scarborough gas field in Western Australian's Carnarvon Basin was discovered in 1979 by the Scarborough-1 well. The field contains about 16 trillion cubic feet original gas-in-place (OGIP) of dry gas. It has been appraised by an additional four wells and the 2004-vintage HEX03A 3D seismic survey. Concepts are currently being evaluated for the field's development.
The field is contained within a large, 800 square-kilometre, very low-relief faulted anticline. The reservoir interval comprises deep water deposits, is divided into a high-quality, high net-to-gross Lower Fan, overlain by lower net-to-gross Middle Fan and Upper Fan. The field is expected to have strong flank and bottom-water drives. The development concepts being considered have minimal tolerance for water production; as such water production is expected to be managed via well shut-ins. Given the low relief of the structure, a significant factor in characterising reservoir performance will be the effect of stratigraphic baffles at various scales, on water movement. Static reservoir models for the Scarborough field were built to incorporate deepwater stratigraphic concepts derived from a plethora of basin-floor fan subsurface and outcrop analogues. These concepts have been applied with systematic distribution of depositional facies, including siltstone baffles bottom-loaded at multiple hierarchical levels.
Dynamic simulation models were built to investigate the sensitivity of sweep efficiency, timing of water arrival and ultimate recovery on a number of key static model parameters. The parameters that were evaluated included: 1) the effect of reduced stratigraphic organisation; 2) the partial removal of baffles at varying stratigraphic levels; 3) the lateral extent and continuity of baffles; and 4) the vertical permeability of siltstones.
The success of the study was facilitated through the effective workings of an integrated, multidisciplinary team of geoscientists and engineers, who maintained frequent communication and feedback through the modeling process.
Total has operated an oil field, offshore Abu Dhabi, since 1972 and, after nearly 40 years of production, the major Lower Jurassic reservoir, has one of the highest oil recovery factors in the UAE owing to a strong aquifer pressure support and a
successful tertiary recovery process. After 16 years of non-miscible gas injection, this EOR technique has significantly improved oil recovery and also brought valuable lessons.
The purpose of this paper is to present the practical challenges encountered and the solutions developed to address the full field tertiary gas injection scheme. Around 28% of the production since field-wide application of the EOR technique has been
attributed to this immiscible process.
Gas injection dynamic behavior is much more sensitive to reservoir heterogeneity than water injection. A more detailed geological and reservoir model was required along with a gas tracer campaign to model properly the well response to the gas
injection. Gravity appears to be the main factor controlling the macroscopic sweep efficiency.
As the full field efficiency is highly dependent on the gas management strategy, an extensive monitoring is required to maximize tertiary oil gains and avoid surface bottlenecking. An analytical methodology was developed to forecast oil gains
and to allocate the gas in the best sectors.
From the beginning of the project, incremental oil gains are in line with the initial objective and have confirmed the added value of immiscible tertiary gas injection in a mature field.
The gas injection will continue in order to pursue the objective to maximize the ultimate recovery of this field by implementing innovative technical solutions. This requires constant vigilance, sound day-to-day reservoir and well management as well as prioritizing tasks with operations' staff on a mature platform with competing processes.
Demulsification is well known and tested, however with regards to heavy oil treatment, the crudes become more difficult to handle. Demulsification is subject to a number of external factors such as temperature, viscosity and crude oil composition, which affect the rate of water drop and resolution of emulsions. Heavy oil is composed of many components, but especially asphaltenes, which are unstable in produced crudes. As a result of their instability, asphaltenes tend to precipitate and fall out of suspension, eventually blocking production flowlines and separators.
It is widely known that many crude oils contain asphaltenes. They affect the oil/water and emulsion separation in these heavy crudes, causing increased usage of demulsifiers and system upsets. There have been many attempts to improve demulsifiers, but this has met with limited success.
We discuss a possible practical chemical technique to help resolve the emulsions in these types of crudes more easily, to maximize separation efficiency.
The use of asphaltene dispersants has been employed to deal with precipitated solids after they have agglomerated, but we investigate examples where the addition of other asphaltene inhibiting products may help improve the demulsification process. The impact of the improved separation would enable the crude oil to better meet its sales specifications. It may also help reduce system upsets and improve the oil production systems, enabling the customer to meet compliance with oil production quotas.