Advanced applications of Modular Formation … No...Advanced applications of Modular Formation...

Advanced applications of Modular Formation Dynamics Tester: Understanding and reducing the uncertainties in reservoir model to optimize production strategies. Rajesh Kumar Singh, Reservoir Engineer; Varun Pathak, Reservoir Engineer Schlumberger Asia Services Limited, Mumbai Abstract: In recent years, the scope and utility of the formation testing and sampling tools has extended far beyond their conventional use for formation pressure measurements and collection of representative fluid samples. Their use now appears at every stage of reservoir management. Successful reservoir management involves characterization of permeability, determination of pressure and fluid distribution, and, in turn, reducing the uncertainties in the reservoir model. Typical uncertain parameters in a reservoir model are horizontal and vertical permeabilities, free water level and fluid contacts, and fluid composition. Correct knowledge of these parameters can influence the reservoir development strategies in immense proportions. Understanding permeability anisotropy is critical for coning and water influx studies, as also for deciding perforation policies. Gas and water influx can significantly reduce oil recovery. An efficient means of estimating permeability anisotropy is the Modular Formation Dynamics Tester (MDT*) using single well numerical model. Using its probe-probe or dual packer-probe configurations, both horizontal and vertical permeabilites can be determined by detecting a response at a detector resulting from a pressure pulse created at a source. Free Water Level (FWL) is another parameter important for deciding development policies. It directly affects the Initial Hydrocarbon in Place calculation, placement of horizontal wells, and reservoir producibility. The best way to estimate the FWL and the transition zone is to observe the change in fluid gradient and “see” the fluid at the dubious depths using Downhole Fluid Analysis (DFA*). Worldwide, vast amount of oil lies in transition zones and DFA is a novel means to characterize the reservoir fluid and determine its transition from oil to water with depth. Compositional Grading of reservoir fluid is another vital attribute achieved with MDT which effects optimizing production strategy, sizing of facilities and keeping production above bubble point pressure. This paper presents the means to achieve the aforementioned objectives through MDT leading to a better reservoir characterization, development strategies and ultimate recovery.

* Mark of Schlumberger

Introduction

With world’s major reservoirs in declining phase, E&P companies are looking towards deep water. Development of a deep water field requires investments in huge proportions. More often than not, data available at the time of finalization of development plan is very little and a lot of uncertainty remains in various parameters that influence the development strategy. During exploration and appraisal phase, a lot of data is acquired to reduce uncertainties related to geology and petrophysical parameters of the reservoir. The process is even more critical because most of the investments are made during this stage when uncertainties are greater. This makes a major impact on investment decisions for the field. There are many uncertainties that can influence the success of an exploration and production project. The most common uncertainties occur in the geological model: volume in place, connected volume, faults, etc. Apart from geological uncertainty, recovery is the most uncertain parameter that depends upon reservoir properties and development strategy. We will discuss in detail about uncertainties in next section. Uncertainties in Reservoir properties: The recovery factor and development strategy is dependent upon reservoir properties like:

• Fluid Properties • Pore Volume • Compressibility • Permeability • Permeability anisotropy and • Relative permeability

All of these properties are measured at laboratory. To be applicable on a reservoir model scale, these properties are to be scaled up. Some of these properties are scale independent like Fluid Properties, Pore Volume, Compressibility and some are scale-dependent properties like Permeability, Permeability anisotropy and relative permeability. For scale independent properties doesn’t require modification during history matching. In scale-up dependent properties, core data availability does not eliminate the uncertainty during scale-up. Generally, uncertainties are associated with scale-up dependent properties. One of the critical parameters that quite often is not given attention during the exploration and appraisal phase is Permeability Anisotropy. Permeability anisotropy has a direct and major effect on establishing producible reserves. Any variation in producible reserves adversely affects the development plan and thus the project economics. Permeability anisotropy also influences completions policy, particularly perforation policy. In deepwater scenario, it becomes even more important to get the right perforation policy right the from field development onset time due to high well intervention costs.


Volume in place estimation involves a number of parameters like porosity, initial water saturation, Free Water Level which have an amount of uncertainty associated. Development policies depend largely upon volume in place primarily. Lot of uncertainties are involved in estimating volume in place like porosity, initial water saturation and free water level, etc. Free water level determination is generally done from the open hole logs. Determining FWL only on the basis of openhole logs like neutron-density, porosity, resistivity can be difficult due to insitu reservoir conditions like effect of capillary pressure, differential depletion etc which can effect the reservoir fluid that will flow during production. Another uncertainty in a reservoir model is fluid properties. PVT properties for a model effect completion strategy, production facilities design, forecasts and ultimate recovery. It is absolutely important to have a representative fluid sample to enable either laboratory determination of properties or downhole fluid scanning to determine the PVT properties accurately. Application of fluid scanning or DFA (Downhole Fluid Analyzer) also appears in determining FWL and establishing compositional grading. MDT*, a wire line formation tester can help in minimizing the uncertainty associated in estimating in Permeability, Anisotropy and DFA* scanning. Conventional ways of measuring Kh/Kv (anisotropy) at reservoir scales have either proved unsuccessful or can only be undertaken once depletion effects become apparent. 1. Permeability and Anisotropy 1.1 Definitions and limitation of conventional measurement Permeability is a rock property and is defined as measure of the ease with which the fluid can flow in a porous medium. Permeability is a tensor, therefore it is direction dependent. Conventionally permeability is determined at core scale in laboratory. Since it is not economical to take core samples throughout the sand, it is often taken at selected intervals of the sand and often core recovered is from the cleanest part of the sand. These few core samples give an estimate of permeability but it is not necessarily a global value that directly related to well productivity. It is always difficult to measure horizontal as well as vertical permeability at core scale due to bad core recovery at tighter part of the reservoir sand. Due to poor measurement of permeability, an uncertainty is always associated with Permeability anisotropy. Permeability anisotropy is defined as: Permeability Anisotropy = Kh/Kv …………………………………………………….eq-1 Where, Kh= Horizontal Permeability, md Kv= Vertical Permeability, md Uncertainty in permeability anisotropy is not only associated with measurement of Kv at core scale but also associated with the conversion of core measurements to reservoir


scale. Anisotropy is a matter of scale. At core scale, each core may be represented as isotropic but when put together, they might be a part of an anisotropic system which represents the reservoir (fig-1). Generally permeability is measured at small core section which can give an incorrect visualization of the reservoir.

Fig-1: Anisotropy - A Matter of Scale Core measured Kh/Kv may bear little resemblance to reservoir model scale depending upon the extent of heterogeneity in the reservoir. Conventional ways of measuring Kh/Kv (anisotropy) at reservoir scales have a lot of uncertainty or can only be undertaken after substantial amount of production from the field. The MDT* Modular Formation Dynamics Tester measurement scale is greater than that for core measurements and offers both versatility and precision to measure anisotropy within and between selected reservoir unit at in situ conditions. 1.2 Principle of MDT measurement permeability The magnitude of the pressure drop recorded during a probe pretest is used to provide a mobility estimate (the “drawdown” mobility). This value includes near-wellbore damage effects, and is not expected to be equivalent to a permeability derived from a well test. It has been shown that this drawdown mobility bears a close relationship to the core permeability. Analysis of the pressure build-up following the pretest drawdown can also provide estimates of spherical and radial permeability. However, the pressure response during this period can be affected by local changes in fluid properties and by small variations in formation properties, damage to the formation resulting from the mechanical setting of the tool, mudcake blocking the probe, and non-Darcy flow near the probe. The use of the pumpout module allows extended testing to be conducted, giving a much larger depth of investigation than is possible with a conventional pretest. The pressure data obtained from pumpout operations (which can be part of a fluid sampling operation) can be interpreted by conventional well test analysis methods to provide formation pressure, permeability and skin8. This technique can be extended by replacing the probe


module with the dual packer module which provides a much larger flow area. This removes some of the limitations imposed by flow convergence into a probe. Permeability estimate is obtained by MDT by doing a “mini-DST”. It is typically done by isolating a 1-m thick interval of the formation using two straddle packers and flowing the reservoir fluid from that interval and then recording a build-up test. Mini-DST is performed to estimate permeability of zone. Definition of fluid properties, together with knowledge of the net pay thickness (from Petrophysical logs and FMI) permit the estimation of formation radial permeability Kr from the permeability thickness product (K*h). An estimate of Openhole skin (combined skin – limited entry, mechanical damage and rate dependent) is also obtained in the analysis. If Spherical Flow is identified prior to Radial Flow it is possible to estimate Kv (vertical permeability) in addition to Kr (radial permeability) and obtain the Kv/Kr ratio. 1.3 Principle of MDT Measurement of Anisotropy Measuring of Permeability anisotropy with the help of MDT is known as Vertical Interference test. The idea behind the Vertical Interference Test (VIT) is to create a pressure pulse in the formation from one probe and then “listen” how this pulse propagates into the formation with different probes set around the one that created the perturbation in the formation. The module used to communicate the pulse to the formation is the dual probe (MRDP). It has two probes at the same depth but facing 180° opposite. One is the “sink probe”, from which the pulse is created. This probe is linked to the flow line through an iso-valve and has only a strain gauge. The second probe is the “horizontal probe”. It is completely isolated from the flowline by tool design and has both quartz and strain gauges. This one“listens” to the propagation in the horizontal direction. Another probe (an MRPS) is placed horizontally above the sink probe and is called “vertical probe”. The spacing of this probe may be adjusted according to the requirements and technical either. This probe “listens” to the pressure propagation in the vertical direction. 1.4 Effect of Permeability and Anisotropy in Reservoir Management Many studies have been done to understand the effect of Permeability anisotropy. The permeability anisotropy affects the displacement efficiency, producible reserve, perforation policy etc. 1.4.1 Displacement Efficiency Displacement efficiency is very important as most of the field is now in depletion stage and undergoing different injection like the gas injection, water flooding, and polymer


flooding etc to increase the recovery from the field. For an example, in homogeneous reservoir model undergoing gas injection, saturation pattern after some time of gas injection will be uniform as shown in fig-2a.In case of heterogeneous formation with discrete permeability barrier, saturation pattern will not be uniform as shown in fig-2b. It is clearly evident that homogeneous or less anisotropy show higher recovery factor in gas injection.

Fig-2a: Saturation Profile in Homogeneous Reservoir Model during Gas Injection

Fig-2b: Saturation Profile in Heterogeneous Reservoir Model during Gas Injection I1.4.2 Producible Reserve It is very necessary to estimate the flow rate and water influx so that a deep water infrastructure plan can be initiated and will complete without delaying the commencement of production. Importance of Anisotropy is driven greatly in offshore environment because of:

• Optimum infrastructure at offshore as it directly affect on project economics • High well intervention cost as many wells are completed as sub sea

Therefore, it is very important to know the relationship between recovery factor and anisotropy. An interesting result of a numerical modeling study is shown in fig-3 as a


curve between producible reserve and Anisotropy. There can be considerable effect of anisotropy on producible reserve.

Producible Reserve, bcf

Fig-3: Effect of Anisotropy on Producible reserve In case of high vertical permeability, significant reserves are trapped behind a rising aquifer. At the other hand, a low vertical permeability may not allow gas recovery from the unperforated layers. For a project economic point of view, it is very important to know estimation of anisotropy so that there will be less uncertainty in producible reserve estimation. 1.4.3 Perforation policy Further more, Anisotropy will also affect perforation policy. In case of high vertical permeability (low anisotropy), perforating only at the top of the layer will be sufficient to drain unperforated layer. Low vertical permeability (high anisotropy) requires greater length of perforation for efficiently draining the whole layer. Perforation policy is more important in deep water where most of the wells are generally completed as Sub Sea where well intervention costs are very high. Sometimes well intervention cost may equal to cost of new well. 2. Free Water Level (FWL) 2.1 Definition Free Water level is defined as the intersection of hydrocarbon pressure gradient and water pressure gradient line as shown in fig-4.. Mathematically, At free water level, Pc=0 Where, Pc= Capillary pressure between hydrocarbon and water


Free water level (FWL) is accepted as the depth at which the capillary pressure between the two phase is zero. Saturation of water (and hence, hydrocarbons) is a function of the capillary pressure above the free water level for a water wetting rock.

Fig-4: Determination of Free Water Level 2.2 Measurement of Free Water Level (FWL) Conventionally free water level is determined by open hole logs.By definition, at FWL, there must be 100% water flow. So in conventional determination of free water level by open hole log, it needs to be confirmed by flow test. Fig-5 shows the confirmation of FWL by MDT flow test. However, by performing a Downhole Fluid Analysis (DFA*), one can actually see if there is 100% flow of water at a particular depth or if there is still the presence of mobile oil. Typically, DFA is performed by pumping the formation fluid using a downhole pump and analyzing it using fluid analyzers in real time. The fluid analyzers differentiate between the phases flowing using optical absorption spectroscopy principles.


3135 m - Oil after

pumping for 59 mins

3136 m

- Oil after pumping for 48 mins

3137 m

- Water after pumping for 90 mins

Fig-5: FWL determination by MDT flow test 2.3 Importance of Free Water Level (FWL) Free water level determination has significant effect on initial hydrocarbon in place. E&P company asset depends on booked reserve and their development strategy is also affected by reserve. Worldwide, vast amounts of producible oil lies in the oil-water transition zones. Fluid contacts and FWL are needed for volumetric calculations, determination of well locations and reservoir producibility forecasts. Changes in FWL can affect the reserve calculations immensely. Even a few feet error in free water level determination will underestimate/ overestimate reserves heavily in case of large areal extant of reservoir. In reservoirs where the density difference between hydrocarbons and water is small, the transition zone will be long and the contact may not be clearly defined. Oil water contact may be used for reserves estimates when the transition zone is short, but in the cases where transition zone is long, this might result in under-estimation of reserves. It is important in such cases to know the FWL. 3. Formation fluid properties and Downhole Fluid Analysis The heart of any reservoir model is the fluid properties. It is a vital input to the simulation model. Accurate PVT properties of reservoir fluid are extremely important for making correct predictions from the simulation. These properties are mostly determined in state-


of-the-art laboratories around the world. But the results are only as good as the samples provided. Quality of samples collected is very important for better reservoir characterization. Bottomhole samples are considered to be representative of the reservoir fluids, if they are acquired at in-situ reservoir conditions and maintained at the same. 3.1 Measurement of Fluid Properties Among the most powerful modules available with the MDT (Modular Formation Dynamics Tester), the LFA* (Live Fluid Analyzer) and the CFA* (Composition Fluid Analyzer) have been well appreciated by several E & P companies. These two modules complement each other and introduce a new concept called DFA (Downhole Fluid Analysis). They provide a measurement of fluid type and composition in real time, which are key issues for decisions in well completion and improve further reservoir characterization and simulation. Two most important conditions for acquiring quality reservoir fluid is minimizing contamination and captured at reservoir conditions and maintaining the same. These are obtained using MDT by typically lowering the tool in front of the zone of interest, inserting a probe into the zone and then flowing the fluids, first filtrate, and then formation fluid, using a downhole pump, monitoring fluid in real-time using the DFA tools, and then capturing a representative formation fluid samples and maintaining it at reservoir conditions. 3.2 Effective Quality Control in Real Time Contamination in Samples is introduced due to foreign particles typically consisting of miscible mud filtrate. Mud filtrate is the first thing that will be introduced into the tool as the investigations are essentially in the invaded zone. Small amount of oil-based mud filtrate contamination is known to have caused drastic changes in the nature of the fluid. DFA techniques like monitoring color and methane content (or GOR) have been successfully implemented to monitor amount of contamination in real-time. Applying these techniques and the correct hardware options, timing of the capture of sample can be made precise so as to capture an ultra low contamination fluid. Maintaining the fluid at reservoir condition is essential to prevent the fluid from undergoing a phase change. Different phases have different mobilities; hence it leads to a non-representative sample. Phase transition may be caused due to variation in pressure or temperature. A slight drop in pressure of the sample bottle might result in liberation of dissolved gas for oil at a pressure close to the saturation pressure. Phase change can be detected by monitoring the downhole fluid analyzers. It can be done by monitoring the composition of the flowing phase and the fluorescence. 3.3 DFA and Compositional grading


Another application of the DFA technique is in the compositional grading of a reservoir. Compositional grading is caused by various reasons. It may be due to segregation of asphaltenes, loss of lighter components, or gravity segregation. Normally, for lighter oils (>35°API), compositional grading is caused by gravity induced component migration that balances the gravitational and chemical forces[6]. For moderately heavier oils (20-30°API), asphaltene segregation[6] is a primary driving force, and in the case of heavy oils (< 20°API) it is often the aftermath of loss of light ends through bio-degradation. Compositional grading can be done using gradients-only approach. But it is better to have DFA stations at the critical depths because gradients alone cannot answer all the questions for such cases as the gradient accuracy itself depends on a number of factors including depth and pressure measurement accuracy, thickness of the zone and number of points attempted. Typically, a number of pressure points are attempted in the critical zones to have a fair idea of the fluid, and DFA stations are carried out selected stations.

Representative formation fluid samples are captured at these depths to have the variation of PVT properties with depth, and to incorporate those in the fluid model. 3.3.1 Importance of Fluid properties DFA is very critical along with the knowledge of contacts and anisotropy for the correct placement of horizontal laterals. In deepwater environment, this becomes even more critical. Typically, the lateral should be places sufficiently above the water zone to prevent water production, and sufficiently below the gas-oil contact to prevent gas coning in an gas-oil-water scenario. A ‘mid-way’ point is suitable if vertical permeability (Kv) is uniform throughout. But if Kv is more for one of the zones out of gas or water, the lateral should be placed away from that zone. Besides these, DFA combined with gradient interpretation can also be used to identify discontinuities in the reservoir, due the geological features. Conclusions 1. MDT permeability data proves useful in refining and qualifying core/log based permeabilities. Permeability measurements made on cores might give different results from in-situ measurements because of change in formation stress and release of fluid during acquiring the core. 2. For comprehensive reservoir characterization, MDT permeabilities from wells in the field, qualified by at least one DST, would result in a more representative reservoir model that may be used for reservoir performance prediction. Permeabilities, both horizontal, as well as vertical can be obtained doing permeability studies using VIT. 3. The initial pressure-gradients plot in multiple layer zones cannot be used to determine whether the reservoir zones will be in differential depletion. 4. For Better field development and better project economic, it will be imperative to know


anisotropy before production especially in deep water field. Since recovery factor and perforation policy can be severally effected by anisotropy. 5. Free Water Level affects the field development decisions like number and location of wells, placement of lateral and reserve estimates. So it is important to establish the exact depth of FWL. 6. Latest techniques in DFA have the capability of real-time insitu characterization of formation fluid and can be successfully used to identify presence of a compositional gradient where gradient analysis does not provide a concrete answer. 7. DFA technology is of primary importance to ensure capturing of representative formation fluid sample during wireline formation testing and sampling runs. These samples are of primary importance to conduct valid PVT experiments and obtaining a set of quality PVT data set for fluid modeling. Nomenclature: Kh, Kr = Horizontal Permeability Kv = Vertical Permeability Pc = Capillary Pressure K = Permeability h = Zone thickness Abbreviations:

MDT* = Modular formation Dynamics Tester FWL = Free Water Level DFA* = Downhole Fluid Analysis DST = Drill Stem Test FMI* = Formation Micro Imager VIT = Vertical Interference Test MRDP = Modular Reservoir Dual Probe MRPS = Modular Reservoir Single Probe CFA* = Compositional Fluid Analyzer LFA* = Live Fluid Analyzer GOR = Gas Oil Ratio

References: , [1] Venkataramanan, L., SPE, Schlumberger, “Downhole Fluid Analysis and Fluid Comparison Algorithm an Aid to Reservoir Characterization” SPE 100937 presented at the 2006 SPE Asia Pacific Oil & Gas Conference and Exhibition , Adelaide, Australia, 11- 13 September 2006 [2] MDT, Schlumberger Publication, [3] Wireline Formation Testing and Sampling, Schlumberger Publication, 1996.


[4] Wannell, M.J. and Coney, N.M., British Gas E&P, and F.R. Halford, Schlumberger Evaluation, “The Use of a New Technique To Determine Permeability Anisotropy”, SPE. 26801 presented at the Offshore European Conference held in Aberdeen, 7-10 September 1993. [5] Widarsono, B., et al “Permeability Vertical –to-Horizontal Anisotropy in Indonesian Oil and Gas Reservoirs” SPE 103315 presented at the Oil Conference and Exhibition in Mexico held in Cancun, Mexico, 31 August-2 September 2006. [6] Hanafy, H.H. and Mahgoub I.S. : “Methodology of Investigating the Compositional Gradient within the Hydrocarbon Column,” paper SPE 95760 presented at the 2005 SPE Annual Technical Conference and Exhibition, Dallas, TX, 9-12 October. [7] Felling, M.M. and Morris, C.W.: “Characterization of In-Situ Fluid Responses Using Optical Fluid Analysis”. SPE 38649 presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas. 5–8 October 1997. [8] Seth, G., Zope, D., Deka, B., Ghosh, B., Joshi, S., Kundu, D.: “Downhole Fluid Analysis and Sampling Establishes Compositional Gradient in a Deep Water Gas-Condensate Reservoir”. SPE 109204 presented at the 2007 SPE Asia Pacific Oil & Gas Conference and Exhibition held in Jakarta, Indonesia, 30 October–1 November 2007. [9] Betancourt, S.S., Fujisawa, G., Mullins, O.C., Eriksen, K.O., Dong, C., Pop, J., Carnegie, A.: “Exploration Applications of Downhole Measurement of Crude Oil Composition and Fluorescence”, SPE 87011 presented at 2004 SPE Asia Pacific Conference on Integrated Modeling for Asset Management held in KL, Malaysia, 29-30 March.


Advanced applications of Modular Formation … No...Advanced applications of Modular Formation...

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