Ultimate Hydrocarbon Recovery Research Articles

Standardization of Particle Size for Floating Particle Wettability Measurement for Carbonate Rocks.

Misrepresentation of the wettability of a reservoir can lead to potentially low ultimate hydrocarbon recovery resulting in substantial economic losses. At the same time, it is impossible to determine the wettability of a reservoir across its length and breadth on a continuous basis using standard procedures. This work presents the development and standardization of a quick, easy, and low-cost wettability measurement method using the adherence tendency of rock particles in the oil or aqueous phase. The most important aspect of this study was establishing the optimum particle size for sustained floatation and balancing the buoyancy and gravity effect. The results show that the particles sink with a larger than optimum particle size because of the gravity effect. Similarly, the particles would float if they are smaller than optimum due to buoyancy and viscosity advantages. A new scale is designed, and the midpoint analysis shows that a 63-90 μm particle size is the ideal size range for the carbonate reservoir's wettability measurements, as the midpoint of the size distribution coincides with the standard Amott-Harvey (A-H) index. However, this size range is found to be wider for oil-wet particles. The floating particle method has several advantages over the established methods once standardized against a reliable process. Not only is the process fast but it can be performed with basic laboratory tools and does not require a high skill set. Most importantly, reliable wettability information can be obtained from drill cuttings and core fragments, enabling the determination of reservoir wettability on a continuum basis and not as a point basis, thus providing a more reliable average value, particularly for heterogeneous and unconsolidated reservoirs.

Time-lapse seismic integrated with surface microseismic for SRV characterization in the Vaca Muerta Formation

Time-lapse (4D) seismic acquisitions were performed in the unconventional play of the Vaca Muerta Formation to monitor hydraulic stimulation efficiency and characterize the stimulated rock volume (SRV) in horizontal drains. Two 4D pilots were carried out by acquiring 3D surveys before and after hydraulic stimulation. The pilots targeted different stratigraphic landings characterized by distinct lithological and geomechanical properties. The 4D pilots were performed in synergy with surface microseismic acquisitions. The combined acquisition enabled joint interpretation of the results. Time-lapse acoustic inversions were performed to identify changes in acoustic impedance. They revealed the vertical dimension of the SRV more precisely than the analysis of the envelope of the wet microseismic events. These wet events are interpreted as hydraulically connected to the well. The 4D signal is interpreted as the envelope of the induced hydraulic fractures, defined here as the fractured rock volume. This volume refers to where the rock frame has been directly affected by the stimulation job. The image provided by 4D seismic represents the most direct and accurate measurement of the volume encircling the flow pathways created by the fracture network generated by the hydraulic stimulation. This information is key to assessing ultimate hydrocarbon recovery and optimizing the development of unconventional reservoirs. The added value of the microseismic is the mapping of subtle events associated with the reactivation of critically stressed faults/lineaments. These provide preferential pathways that could connect to the well. They also help in the understanding of hydraulic interactions between the wells and their individual SRVs. The findings of these studies indicate that the optimal lateral and vertical well spacing should be designed based on 4D monitoring for drainage optimization and on microseismic for the analysis of interwell structural interferences.

Impact of Reservoir Heterogeneity on the Control of Water Encroachment into Gas-Condensate Reservoirs during CO2 Injection

Abstract The paper evaluates application of CO2 injection for the control of water encroachment from the aquifer into gascondensate reservoir under active natural water drive. The results of numerical simulations indicated that injection of CO2 at the initial gas-water contact (GWC) level reduces the influx of water into gas-bearing zone and stabilizes the operation of production wells for a longer period. The optimum number of injection wells that leads to the maximum estimated ultimate recovery (EUR) factor was derived based on statistical analysis of the results. The maximum number of injection wells at the moment of CO2 break-through into production wells for homogeneous reservoir is equal to 6.41 (6) and for heterogeneous – 7.74 (8) wells. Study results indicated that with the increase of reservoir heterogeneity, denser injection well pattern is needed for the efficient blockage of aquifer water influx in comparison to homogeneous one with the same conditions. Gas EUR factor for the maximum number of injection wells in homogenous model is equal 64.05% and in heterogeneous – 55.56%. Base depletion case the EURs are 51.72% and 49.44%, respectively. The study results showed the technological efficiency of CO2 injection into the producing reservoir at initial GWC for the reduction of water influx and improvement of ultimate hydrocarbon recovery.

Experimental analysis of hybrid low salinity water alternating gas injection and the underlying mechanisms in carbonates

Enhanced oil recovery methods have been widely used around the world to improve ultimate hydrocarbon recovery. Among them, low salinity water flooding has gained attention as a practical enhanced oil recovery method which modifies the rock wettability to a more hydrophilic state. Besides, gas, mainly CO2, injection by means of water alternating gas process is proved to improve un-swept oil recovery due to the mobility control of displacing fluids. Hence, the mutual application of these two enhanced oil recovery techniques, as low salinity water alternating gas) injection, benefits the driving mechanisms subjected by both methods resulting in higher oil production. In this study, a series of experiments including contact angle measurements, gas solubility in brine, emulsion formation, and coreflooding were conducted. Wettability alteration of the carbonate samples towards the more water wet state was observed by the contact angle measurements for diluted sea waters which shows salinity of the injected water can play a significant role in the enhancement of ultimate oil recovery. 10 times diluted brine was found to be the optimum one which changed the contact angle for 52°. It shows that there is an optimum concentration for different CBR systems under which the available PDIs are not sufficient to alter the rock wettability to a greater extent. The presence of gas phases favorably improved the wettability modification. The successful performance of 10 times diluted brine was also confirmed by emulsion formation tests. For this case, the number of the generated water in oil emulsion droplets was 1.54 times that of SW. Stable emulsions enhance the oil displacement through provoking wettability alteration by low salinity water and mobilizing the residual oil via the osmotic effect. Finally, a 10.8% incremental oil recovery by low salinity water alternating gas flooding verified the synergistic effects of this method regarding enhanced oil recovery.

Approval of the technology of carbon dioxide injection into the V-16 water driven reservoir of the Hadiach field (Ukraine) under the conditions of the water pressure mode pages 1–2

The object of research is water-driven gas-condensate reservoirs. Using the main hydrodynamic modeling tools Eclipse and Petrel from Schlumberger (USA), the study was carried out to improve the existing technologies for the displacement of residual gas reserves by carbon dioxide from the water-driven gas-condensate reservoirs. The carbon dioxide injection technology was tested in the V-16 reservoir of the Hadiach oil and gas condensate field (Ukraine). According to the study results, it was found that due to the injection of non-hydrocarbon gas, the cumulative water production are reduced compared to the depletion. Based on the obtained modeling results, the calculation of the predicted hydrocarbon recovery factors at the moment of carbon dioxide breakthrough into the production well was carried out according to the cumulative formation water production. According to the calculations, it was found that the implementation of the enhanced gas recovery technology provides significantly higher ultimate hydrocarbon recovery compared to the depletion. The predicted gas recovery factor when injecting carbon dioxide into the V-16 reservoir increases by 2.95 % of the residual gas reserves, and the condensate recovery factor for these conditions by 1.24 %. Based on the study results, the technological efficiency of using carbon dioxide as an injection agent to increase the hydrocarbon recovery from water-driven reservoirs was established. According to the simulation results, the implementation of the technology of carbon dioxide injection into the V-16 reservoir of the Hadiach oil and gas condensate field can significantly increase the hydrocarbon recovery from the deposit, thereby increasing the production capacity of the field.

Reservoir heterogeneity of Ordovician sandstone reservoir (Bedinan Formation, SE Turkey): Diagenetic and sedimentological approachs

The sandstone-bearing reservoir levels (Bedinan Formation) in the Diyarbakır Basin, SE Turkey show strong heterogeneity in porosity, permeability and capillary pressure, which influences oil production rates of the studied 6 wells and beclouds the prediction of hydrocarbon reserves. Therefore, comprehensive understanding of the sandstone reservoir characteristics has been necessitated to optimize its ultimate hydrocarbon recovery, maximize its lifetime and to make more accurate performance predictions for the use in economic risk assessment. In this study, integrated analysis of paleogeography, depositional characteristics, petrographic features, provenance, pore structure, reservoir heterogeneity rating, diagenetic stage and its possible impacts on reservoir quality were examined by employing thin section analysis, sedimentary structure analysis, petrophysical interpretations, geostatistic methods, X-ray diffraction (XRD) and non-destructive X-ray computed tomography. It is concluded that the Upper Ordovician sands were laid down under shallow marine conditions (lower shoreface to upper shoreface) in an ice-distal glaciomarine environment and have been subjected to a complex history of diagenesis. The sandstone succession was sourced from plutonic rocks and derived from a stable craton. The presence of detrital and diagenetic rooted clay-coating minerals (illite, kaolinite, illite/smectite mixed clay layer) together with cementation by quartz overgrowth and carbonate concretions in the matrix of the sandstone layers are the main factors deteriorating the reservoir quality by plugging pore throats and decrease production rates and oil recovery. However, the type of clay-coating minerals and the amount of those are the key factors modifying reservoir architecture in comparison with the cementing materials. Besides that the integration of illitization of kaolinite and smectite in mesodiagenetic stage, the presence of minerals such as quartz, feldspar and illite altering the pore spaces from oil-wet to water-wet and compaction induced micropores are culprits in causing high water saturation in the sandstones even in the zone above oil-water contact.

Estimating compressibility of complex fracture networks in unconventional reservoirs

Previous studies show that fracture closure is the primary drive mechanism for fracture cleanup during flowback process in hydraulically stimulated reservoirs. Estimating fracture compressibility is practically essential to calculate effective fracture volume, evaluate fracture volume change, and forecast ultimate hydrocarbon recovery. However, limited experimental data are available for evaluating compressibility of fracture networks in unconventional reservoirs. In this paper, we categorize induced fractures into unpropped and propped fractures, and estimate their compressibilities from fracture conductivity measurements and Hertzian contact theory, respectively. We also investigate the effects of rock and proppant parameters on fracture compressibility. Finally, we propose a workflow to estimate compressibility of complex fracture networks and investigate the roles of propped and unpropped fractures during fracture closure. The results show that fracture compressibility depends on how fracture porosity and aperture change with effective stress. For propped fractures, the rate of porosity change primarily controls fracture compressibility. In addition, compressibility of complex fracture networks approximates that of unpropped fractures at low effective stress and that of propped fractures at high effective stress. Overall, the results highlight the role of unpropped fractures in hydrocarbon recovery from stimulated unconventional reservoirs.

On the Optimum Aging Time: Magnetic Resonance Study of Asphaltene Adsorption Dynamics in Sandstone Rock

Wettability is a key factor defining ultimate hydrocarbon recovery. Extensive experimentation is required to replicate the wetting state of reservoir rocks. This involves a rock sample wettability restoration procedure, including an aging step and a concept of an optimum aging time, in which asphaltene chemistry plays a major role. There are numerous reports on significance of various crude oil components and elements of asphaltene structure to their tendency to interact with the solid phase, though subject evidence is contradictory. We investigate a possible relationship between the composition of oil, kinetics of an aging process, and a change of sandstone rock wettability. Wettability state of the cores was monitored using low-field NMR relaxometry. The composition and key components of accumulated deposits were established by matching 1H solution-state NMR and X-band EPR spectra of deposits to the spectra of SARA (saturates-aromatics-resins-asphaltenes) fractions of aging fluids. We determined adsorpt...

Unified Theory of Ultimate Hydrocarbon Recovery for Primary and Cyclic Injection Processes in Ultratight Reservoirs

This paper presents a simple method to estimate ultimate recovery factors (URF) of ultratight reservoirs based on equilibrium by diffusion in which URF is only a function of changes in hydrocarbon density between initial and final states. URF is defined at infinite time and therefore does not depend on the transient behavior. Although URF may not be achievable during the life-cycle of the field development and production, it provides valuable insights on the role of phase behavior. We show that equilibrium phase behavior defines the absolute upper-bound for URF during primary production and explains the poor recovery from shale oil reservoirs compared to the high recovery factor in shale gas reservoirs in a unifying way. Further, we quantify how injected solvent compositions (CH4, CO2, N2, and C2H6) during huff’n’puff enhanced oil recovery (EOR) improve recovery based on density reduction and compositional dilution, and show that the largest percentage increase in recovery occurs for heavier oils. Our calculations provide a practical means to define the URF from primary production as a function of reservoir fluid composition, temperature, and pressure drawdown. In addition, our calculations articulate incremental URF (IURF) of solvent huff‘n’puff based on net solvent transfer into ultratight rock, which is a key design consideration. The results illustrate that solvent transfer dilutes the hydrocarbons in place, thus maximizing long-term hydrocarbon recovery. Net mass transfer can be improved by enhancing the diffusion of solvent into the matrix based on the huff‘n’puff design parameters including solvent composition, drawdown pressure, and the net amount of solvent injected based on optimal frequency and cycle duration.

An integrated quantitative approach for determination of net reservoir cutoffs: A case study of Q oil field, Lake Albert, Uganda

Petrophysical cutoff of net reservoir plays a very important role in reservoir characterization for the evaluation of hydrocarbons in place and the estimation of ultimate hydrocarbon recovery. There have been many approaches to quantify cutoffs, yet each of these approaches yields a different reservoir model with some amount of uncertainties due to lack of enough data, insufficiency of knowledge and the heterogeneous nature of petroleum reservoirs. Conventionally, net reservoirs cut-offs are evaluated by applying static petrophysical well-logs without consideration of dynamic performance, which results in a crisp classification of reservoir or non-reservoir zones. This paper takes Q oilfield in Albert Basin of Uganda as an example, provides a new structured quantitative approach which integrates all core, petrophysical interpretation, modular dynamics test data, reservoir fluid data and development wells pattern together to determine a reasonable net reservoir cutoffs. Three dependent variables including oil initially in place (OIIP), total oil production (FOPT) and total water production (FWPT) were selected to test the sensitivity with two independent variables, i.e. volume of clay (Vclay) and porosity. Then experiment design and response surface method were used in constructing the proxy models that are related to the dependent variable. After running 5000 realizations, probability density function (PDF) was utilized to locate P50 value on the cumulative probability curve. Finally, the cutoffs of Vclay and porosity were determined by the arithmetic mean of corresponding P50 value. The case study clearly illustrates how all available data from a reservoir should be integrated for appropriate determination of the net reservoir cutoffs.

A fully compositional model considering the effect of nanopores in tight oil reservoirs

Conventional compositional simulators are usually difficult to interpret the different gas oil ratio (GOR) from tight oil reservoirs, and this also indicates an unreliable prediction of ultimate hydrocarbon recovery. We realize that there are two issues related to the compositional simulation of production in tight oil reservoirs. Firstly, tight oil reservoirs typically exhibit extremely small matrix pore size in the order of nanometers, so the capillary pressure between vapor and liquid phases is considerable such that the PVT of the confined fluid deviates from that of the bulk fluid with capillary pressure ignored. Secondly, during depletion process, rock compaction causes pore space reduction and brings remarkable changes in rock properties. In this work we implement rigorous confined fluid phase behavior calculation depending on capillary pressure and rock compaction in a fully compositional simulator. Capillary pressure in matrix nanopores is calculated by Leverett J-function. Further, the impact of capillarity on phase equilibrium is taken into account through modifying the stability test and two-phase flash calculation. Dynamic rock compaction is considered in the simulator via rock compaction tables, such that fluid mobility decreases with permeability reduction and capillary effect is simultaneously coupled. The unique implementation in the simulator captures the dynamic behavior of rock and fluid properties in tight oil reservoirs. Typical suppression of bubble point pressure and reduction of oil viscosity and density is observed from our simulation results. Reservoir-scale simulation results show that this model resolves the problem of the inconsistent GOR in tight oil production and greatly facilitates the history matching process. The enhanced compositional simulation will ultimately improve our understanding of tight oil reservoirs and provide better guidance for recovery prediction.

Unconventional resource's production under desorption-induced effects

Abstract Thousands of horizontal wells are drilled into the shale formations across the U.S. and hydrocarbon production is substantially increased during past years. This fact is accredited to advances obtained in hydraulic fracturing and pad drilling technologies. The contribution of shale rock surface desorption to production is widely accepted and confirmed by laboratory and field evidences. Nevertheless, the subsequent changes in porosity and permeability due to desorption combined with hydraulic fracture closures caused by increased net effective rock stress state, have not been captured in current shale modeling and simulation. Hence, it is essential to investigate the effects of induced permeability, porosity, and stress by desorption on ultimate hydrocarbon recovery. We have developed a numerical model to study the effect of changes in porosity, permeability and compaction on four major U.S. shale formations considering their Langmuir isotherm desorption behavior. These resources include; Marcellus, New Albany, Barnett and Haynesville Shales. First, we introduced a model that is a physical transport of single-phase gas flow in shale porous rock. Later, the governing equations are implemented into a one-dimensional numerical model and solved using a fully implicit solution method. It is found that the natural gas production is substantially affected by desorption-induced porosity/permeability changes and geomechancis. This paper provides valuable insights into accurate modeling of unconventional reservoirs that is more significant when an even small correction to the future production prediction can enormously contribute to the U.S. economy.

Sand-Control Reliability: Finding the Sweet Spot

Guest editorial Sand control represents a diverse range of technologies designed to meet the demands of hydrocarbon recovery from weak sandstone formations. Although the technology is developing and improving, industry adoption of new sand-control techniques is typically much slower than for oilfield technologies in general. While is it often necessary to control the unwanted production of reservoir sand into the wellbore, sand-control techniques to varying degrees add cost and complexity, yet are operationally unforgiving and have relatively poor long-term reliability. Added to that is a single-point critical failure mode in a completion that is often both unrecoverable and unrepairable. The challenge, then, is to provide sand-control technology that addresses these weaknesses and to select solutions that will maximize value for any given application. This fundamental challenge is unchanged from the time when sand control was first installed in wells more than 100 years ago; what has changed is the variety and complexity of applications. For example, extended reach, high rate, deep water, high-pressure/high-temperature, heavy oil, multilateral well construction, and reservoir segmentation all place differing demands on the sand-control completion but all represent higher-cost environments in which maximizing the return on investment is essential. In response to this increasing diversity and criticality, the industry has seen an increasing range of sand-control techniques. There are now at least 20, many of which are “new,” have evolved, or are under development. But since none is a panacea, how do we evaluate and rank this increasing range of options and application challenges to maximize net present value (NPV)? There are three key factors in determining NPV: cost, performance, and reliability. The cost element is relatively simple. Operating expenditure, capital expenditure during installation, and the cost of failure—lost production and remediation—can be readily quantified. And generally, even for new techniques, the tools exist to model the well performance and confidently predict (at least) relative performance. While the performance of sand-control completions for some solutions is determined by the productivity reduction that occurs due to skin damage or wellbore size reduction, performance can also be positively influenced. Sand control with stimulation techniques or chemical treatments can increase productivity, and inflow-control technology can be combined to aid wellbore cleanup and improve ultimate hydrocarbon recovery. More recently, options for additional functionality have been introduced to provide degrees of reservoir management. Having quantified cost and performance, what is left is reliability, and herein lies the challenge that is in many ways unique to sand control.

A Procedure for Assessing the Value of Oilfield Sensors

Summary Spurred by improvements in reliability, cost, and accuracy, sensors offer a means of increasing expected ultimate hydrocarbon recovery in producing assets as well as in planned and prospective projects. Ultimate hydrocarbon recoveries larger than those currently achieved are possible, especially when sensors are used with advanced recovery methods. However, it is often unclear if the incremental recovery justifies the cost of installing the sensors. This paper proposes a method for estimating incremental values attributable to real-time sensors and provides a demonstration of the method for several production technologies and reservoir settings. The method offers a transparent and practical means of making value of information (VOI) computations to be implemented readily by project teams. An additional benefit of this method is that the process of specifying the inputs to the analysis facilitates a systematic discussion of strengths and weaknesses, and builds consensus regarding assumptions. The method is applied to four scenarios developed by a panel of industry experts to represent generic, but yet realistic reservoirs. The results for these scenarios indicate the value of sensors depends on the market price for product and the type of reservoir and production technology. The greatest absolute economic value for the use of sensors is obtained for a deepwater reservoir, while the greatest economic value per equivalent barrel of oil produced is obtained for a mature onshore reservoir. These expected economic values are intended to be compared to the cost required to implement the sensors to assess whether or not there is an expected net benefit.

The Application of Cutoffs in Integrated Reservoir Studies

Summary Methodologies have been developed for applying net reservoir and thence net pay cutoffs in cases of primary and waterflood depletion. The cutoffs are dynamically-conditioned to be reservoir-specific (i.e., they are tied back to a reference permeability parameter in a way that is driven by the reservoir data themselves). They also honor scale, where feasible, and are conformable with any pertinent rock-typing. For primary depletion, the Leverett equivalent circular pore diameter has been used to distinguish between reservoir and nonreservoir rock. This composite parameter can incorporate mobility for multiphase work. It is linked to a discrete core porosity under simulated reservoir conditions, so the adopted net reservoir cutoff is expressed as a limiting porosity. For waterflood depletion, an extrapolated endpoint relative permeability to oil has proved effective for the same purpose. Here, the zero endpoint relative permeability is linked to a conventional "absolute" core permeability corrected to reservoir conditions. Porosity is tied back to this limiting absolute permeability so that the net reservoir cutoff is again expressed in terms of porosity. Consequently, in both cases, the discrete porosity cutoffs have a dynamic significance. Other cutoff parameters, such as shale volume fraction and water saturation, can be tied back to these. A proposed workflow for applying dynamically-conditioned cutoffs allows data character to drive their use in integrated reservoir studies. The workflow constitutes a basis for greater technical consistency in the estimation of ultimate hydrocarbon recovery. However, the treatment is not exclusive, and other approaches to the determination of net pay will emerge as more reservoirs are considered.

Technology Focus: Completions Today (September 2008)

Technology Focus I am not here to discuss the process of detailing the optimum completion design. However, I do believe that there is no single parameter to serve as the "rule of thumb" to judge well-completion designs for the life of the field. Earlier this year, I attended the first SPE Unconventional Reservoirs Conference at Keystone Resort and Conference Center, in Keystone, Colorado. Afterward, I attended a workshop presented by Shell Energy Canada and Calgary Research Centre. Both presentations highlighted the emerging and applied technologies in use worldwide for recovery of unconventional hydrocarbon resources. As with all conferences, I had the opportunity to engage in discussion with many world experts from various operating/service companies and academia. After thorough discussions with all parties, I have reviewed an abundant reference list on well completions that use sonic stimulation. Many were anecdotal. Some may argue this was because of the nature of the studies, in which improved production was observed after some coincidental event that may or may not have been responsible for incremental hydrocarbon production. In my opinion, all studies should be scientific, not anecdotal, so long as the sonic stimulation was applied with the intent of enhanced hydrocarbon production. Thorough discussions, backed with research on this subject, ensure that certain aspects of the well's operation, such as safety, availability, and efficient use of equipment inventory, are not overlooked. Many readers will agree that not all well completions achieve this objective. I have found that many unconventional-reservoir failures may not be a function of the manner in which they were designed, but may be simply the result of purely unknown complex reservoir-related mechanisms. I advocate that operating companies use advanced diagnostic procedures that match and predict performance to estimate reservoir potential, well deliverability, and completion efficiency accurately. I believe in focusing on some of the best practices, such as economics (i.e., net present value), as the main driver. Hence, alternative completions such as sonic stimulation may be a viable alternative to reduce workover costs and improve ultimate hydrocarbon recovery. Completions Today additional reading available at the SPE eLibrary: www.spe.org SPE 113106 • "Optimization of Completion Interval To Minimize Water Coning" by M. Tabatabaei, SPE, University of Louisiana at Lafayette, et al. SPE 113670 • "Through-Tubing Inflatable Technology Deployed on a Downhole-Tractor System Provides Real-Time Cost Savings" by Graeme M. Kelbie, SPE, Baker Oil Tools, et al. SPE 108656 • "Harsh-Environment HP/HT Gas-Condensate Production Cleanup Experiences—Kristin Field" by Arild Fosså, Expro, et al. Additional reading available at OnePetro: www.onepetro.org OTC 19341 • "Expandable Screens: Optimized Horizontal Gas Production Through Collaboration" by Alejandro Lopez Lara, Pemex, et al.

Overview: Completions Today (September 2006)

The clear objective for any well is that it should perform to the full potential of the formation it penetrates and remain stable throughout its lifetime. This goal is best achieved by avoiding formation damage in the first place, but in most cases this is not possible. In reality, all reservoirs are damaged to some extent by drilling/completion fluids. The important issue is whether this damage affects well productivity significantly. Optimum completion design is essential in maximizing the value available from the reservoir. Poorly planned or executed completion strategies can easily reduce production (and revenue) streams by up to 50%. While there appears to be a consensus on the mechanism of formation damage, there is growing divergence over how it may be combated or avoided. Recent research indicates that fluctuations in wellbore pressure during the first milliseconds after perforation-gun firing govern the perforating-tunnel cleanup, rather than the initial static underbalance as originally thought. A completion design in which perforating bypasses invasion combined with a new design that ensures dynamic underbalance at all times has yielded very good results. Intelligent-completion technologies provide downhole sensing and communication and remote control of completion tools. This technology allows operators on the surface and in remote locations to optimize reservoir performance by interpreting downhole data in real time, then operating flow-control devices accordingly. To get a broader uptake of intelligent-completion technologies, there is a need for compelling success stories documenting the value of new and existing technology. Sharing these experiences could increase opportunities for broader implementation among operators of both conventional and unconventional reservoirs. With the current oil and gas revenues, many opportunities exist for major operators to spend more capital on intelligent-completion technologies; a 10 to 20% increase in hydrocarbon recovery can balance the risks and opportunities of investing in challenging projects and the capabilities to bring them to fruition. The willingness to share success stories as well as failures when documenting new technology is an important factor in achieving faster deployment of advanced completion technologies. As this concept becomes a reality in more fields, the upstream petroleum industry will enjoy increased efficiency and ultimate hydrocarbon recovery at lower cost. Considering that completion takes a substantial stake in the total capital expenditure for a new well, the cost and effect of the well completion is too significant to be ignored. Completions Today additional reading available at the SPE eLibrary: www.spe.org SPE 97175 "External Casing Perforating Provides Optimal Treatment Coverage in Horizontal Pay" by J.L. Rodgerson, BJ Services Co., et al. SPE 99691 "First Through-Tubing Gravel-Pack Recompletion Performed in Japan" by M. Numasawa, Japan Petroleum Exploration Co. Ltd., et al. SPE 100413 "Efficient Cost Saving Through an Appropriate Completion Design" by L.-B. Ouyang, Chevron Energy Technology Co., et al. SPE 96395 "Numerical Investigation of Horizontal-Well Performance With Selective Completion" by R. Kalita, Schlumberger, et al.

The Role of Cutoffs in Integrated Reservoir Studies

SummaryThere have been many different approaches to quantifying cutoffs, with no single method emerging as the definitive basis for delineating net pay. Yet each of these approaches yields a different reservoir model, so it is imperative that cutoffs be fit for purpose (i.e., they are compatible with the reservoir mechanism and with a systematic methodology for the evaluation of hydrocarbons in place and the estimation of ultimate hydrocarbon recovery). These different requirements are accommodated by basing the quantification of cutoffs on reservoir-specific criteria that govern the storage and flow of hydrocarbons. In so doing, particular attention is paid to the relationships between the identification of cutoffs and key elements of the contemporary systemic practice of integrated reservoir studies. The outcome is a structured approach to the use of cutoffs in the estimation of ultimate hydrocarbon recovery. The principal benefits of a properly conditioned set of petrophysical cutoffs are a more exact characterization of the reservoir with a better synergy between the static and dynamic reservoir models, so that an energy company can more fully realize the asset value.

Underbalance Perforation in Long Horizontal Wells in the Andrew Field

Summary Andrew field in the U.K. Continental Shelf, which is operated by British Petroleum (BP) Exploration, is being developed using horizontal oil producers and completed with cemented liners. The main challenges of perforating these wells are maximizing well productivity by avoiding formation damage, minimizing the possibility of sanding, maximizing ultimate hydrocarbon recovery, perforating long horizontal sections safely and efficiently, optimizing the economic value of perforating, and minimizing perforating debris. In general, to avoid impairing well productivity, it is best to perforate the underbalance. However, the advantage is compromised, because of the fluid invasion and loss-control material, if a well will be killed when the tubing-conveyed perforating (TCP) guns are removed. Existing deployment methods with coiled tubing (CT) enable perforation and subsequent gun removal in an underbalance condition. Unfortunately, various limitations would require multiple runs with CT for perforating each horizontal well in the Andrew field, which would result in significant time and unbalance perforation for each subsequent run. The combination of the newly developed mechanical ball valve and the deployment of TCP guns with hydraulic workover units enables long horizontal wells to be perforated in one run in underbalance, and enables the guns to be removed without killing the well. Specially engineered guns and perforating charges are used to minimize sanding and gun debris. This paper describes how these new technologies, used for perforating operations, meet many challenges. The same technologies can be used readily for perforating other long horizontal wells with similar problems. To date, three horizontal wells in Andrew field were perforated successfully with the method described in this paper. The initial results indicate that the combination of the cemented liner completion, the engineered perforation systems, and the correct TCP gun deployment method using the mechanical deployment valve have contributed to improve well performance, to reduce cost, and to improve operability and safety in long horizontal wells.

Estimation of ultimate recovery for UK oil fields; the results of the DTI questionnaire and a historical analysis

The UK Department of Trade & Industry (DTI) recently sent out a questionnaire (see Appendix) to North Sea operating oil companies to survey the different methods used in the estimation of ultimate hydrocarbon recovery and production forecasting. The feedback revealed significant differences in approach between operators in estimation methods and also a wide range of perceptions of the value and accuracy of ultimate recovery and production forecasts. This paper reports the findings of the survey and also takes a historical look at how accurate ultimate recovery estimates have actually been for UK Continental Shelf oil fields developed over the last decade. Historical reserves estimates have been rather inaccurate, with many fields exhibiting changes in estimated ultimate recovery over a ten-year period of over 50%. These inaccuracies have had a severe effect on facilities requirements for many large North Sea fields. The fields studied have required an average of 60-80% more wells than anticipated at the time of Development Plan submission and up to 400% average increase in platform water handling capacities has been necessary. Average field lifetimes have been over a decade longer than originally expected. Accommodating unexpected changes of this magnitude within existing offshore facilities has proven a very expensive exercise and we therefore suggest there is a need for a more unified approach by the industry to ultimate reserves estimation.