ibp1970 06 fluid sampling optimization process with ... · 1 msc, petroleum and reservoir engineer...

________________________________________ 1 Msc, Petroleum and Reservoir Engineer - Schlumberger Serviços de Petróleo LTDA 2 Bs, Petroleum Engineer and Logging Engineer – Schlumberger Serviços de Petróleo LTDA

IBP1970_06

FLUID SAMPLING OPTIMIZATION PROCESS WITH

WIRELINE FORMATION TESTERS

Jesús A. Cañas1, Adolpho Souza

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Copyright 2006, Instituto Brasileiro de Petróleo e Gás - IBP

Este Trabalho Técnico foi preparado para apresentação na Rio Oil & Gas Expo and Conference 2006, realizada no período de 11 a 14 de setembro de 2006, no Rio de Janeiro. Este Trabalho Técnico foi selecionado para apresentação pelo Comitê Técnico do evento, seguindo as informações contidas na sinopse submetida pelo(s) autor(es). O conteúdo do Trabalho Técnico, como apresentado, não foi revisado pelo IBP. Os organizadores não irão traduzir ou corrigir os textos recebidos. O material conforme, apresentado, não necessariamente reflete as opiniões do Instituto Brasileiro de Petróleo e Gás, seus Associados e Representantes. É de conhecimento e aprovação do(s) autor(es) que este Trabalho Técnico seja publicado nos Anais da Rio Oil & Gas Expo and Conference 2006.

Resumo

A caracterização do fluido é fator chave para o desenvenvolvimento de um campo, isto inclui otimização da recuperação do hidrocarboneto como também o projeto apropriado do sistema de produção.

Este artigo descreve um processo para otimização de amostragem de fluidos de poço a cabo em diferentes condições de poço, reservatório e tipo de fluido.

Com base em experiências de campo, laboratório e analíticas, um processo foi desenvolvido para permitir amostragem de fluido e teste de formação in-situ em formações inconsolidadas, reservatórios fraturados, sistemas de baixa capacidade de fluxo ou com tendência de emulssificação e fluidos corrosivos. Este processo considera as vantagens de novos meios para identificação de fluido, capacidade de bombeio e armazenamento da amostra. Acima disto uma série de boas práticas e simuladores especiais foram estabelecidos para seleção apropriada de ferramentas e técnicas de acordo com condições de poço e reservatório.

Dentre os novos módulos envolvidos está o Extra Large Diameter Probe, o Módulo com dois probes concêntricos para fluxo focalizado, Dual packer com filtro para controle de sólidos, e borrachas especiais; Bombas de super baixa vazão, sensores avançados para análise de fluido no fundo e amostrador monofásico de alta capacidade de armazenamento.

Nas boas práticas inclui-se análise das propriedades mecânicas da rocha para definir taxa de fluxo aplicada e seleção de filtros de forma a minimizar fenômeno de plugueamento; amostragem por técnica de segregação para otimizar tempo de amostragem e contaminação; como também simulações para planejar o trabalho.

Vários exemplos de campo são apresentados para ilustrar estas práticas de amostragem de fluido de poço.

Abstract

The reservoir and fluid characterization is a key aspect for field development. This fact turns to be more critical in reservoirs with high heterogeneity (laminations, natural fractures, double porosity, digenesis, etc), low permeability, limited flow assurance and complex fluids or wellbore conditions.

This paper describes an integrated approach for fluid sampling optimization as per reservoir, fluid type and bottom hole conditions, using Wireline Formation Testers.

Based on field and lab experience a workflow process was developed to allow complex fluid sampling and in-situ formation testing in low consolidated formations, fractured or tight reservoirs, unstable wellbores, difficult geometrical well or deployment conditions (deviated and horizontal wells throughout the reservoirs), deep water operations in heave rough seas and oils with emulsification tendency or corrosive fluids.

This workflow process considers the advantages of new modules or best practices for fluid identification, pumping capabilities and sampling storage, such as the Extra Large Diameter Probe, Focused Probes, Dual Packer with filters for solids control and high temperature, Extra High-Pressure Displacement Units for low flow rate, advanced down hole fluid analysis sensors, Single-phase Samplers of higher storage capacity. Among the new best practices we include rock mechanics properties guidance’s for flow rate and required flow area selection, reverse and Low-Shock Sampling, and the Down hole Segregation Technique (DhSEG).

Field examples are presented to prove the advantages of these technologies.

Rio Oil & Gas Expo and Conference 2006

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1. Introduction

Mechanically unconsolidated formations combined with viscous oil poses a challenge for open hole sampling. In order to find a solution to this problem, it is necessary to understand the associated mechanisms.

Other challenge environment for fluid sampling and testing are the naturally fractured reservoirs which are composed of highly permeable fracture network and low permeability blocks whose average dimension is controlled by the fracture density. However, the wireline logging techniques evolved with the advent of resistivity imaging (Fullbore Formation Micro Imager tool) that allows fracture detection and quantitative evaluation, and the capabilities of the Modular Formation Dynamics Tester to straddle fracture intervals (dual packer), identify fluids, take samples, and acquire data for transient pressure analysis of the interval. Similar conditions could be offered by the highly laminated reservoirs. In both cases the dual packer adds a new dimension to the reservoir evaluation and fluid sampling.

In the other side, we have the tight formations, which are prone to high invasion as function of the drilling overbalance conditions and slow reservoir inflow during sampling operations. This generates lengthy periods for fluid sampling and pressure buildup times during formation pressure measurements

Complex native fluids, such as sour Gas Sampling, is another element to be considered in order to have representative native fluid samples and protect the involved personnel. Testing these wells with conventional methods can be technologically expensive and environmentally challenging. The modular formation tester (WFT) provides an excellent alternative to test these sour gas formations with out exposing it to the environment. By using H2S-rated sample chambers, WFT tools can effectively contain the whole operation in the downhole, successfully conducting pressure tests and sampling, avoiding using any surface facilities.

Additionally to the objective of sampling fluids with none or almost nil contamination, another important issues to consider in fluid sampling operation are the need to reduce operational time and associated risks in unstable wellbores, geometrical conditions of the wells (deviated and horizontal wells throughout the reservoirs), handling deep water operations in heave rough seas and guaranty safe tool deployment.

2. Process

In this section we describe an integrated approach for fluid sampling optimization as per reservoir, fluid type

and bottom hole conditions, using Wireline Formation Testers. The process presented in Figure 1 is based on an integrated appraisal process that includes: - Clear job objectives and priorities, meaning, the type of required down hole fluid analysis (fluid scanning

along a reservoir column, combination of fluid identification and sampling stations, single phase or PVT samples, etc),

- Definition of the expected fluid to be sampled based on local experience, mud logging information and preliminary open hole logging analysis (magnetic resonance, conventional logs, etc),

- Reservoir flow parameters such as the expected range of permeability (magnetic resonance, K-Elan permeability, etc.), anisotropy and porous system model (magnetic resonance, resistivity and sonic scanning),

- Estimated filtrated invasion and formation damage (array resistivity logs, sonic scanning), - Formation and wellbore stability estimations based on mechanical properties - Young Modulus, Poisson

Ratio- (unconfined compressive stress, minimum stress and critical draw down), effective porosity and pore pressure from formation tester pretests,

- Wellbore geometry and trajectory regularity and complexity, - Bottom hole pressure and temperature, - Mud type, including solid contents, and differential pressure, - Water depth and expected sea heave roughness to reduce risk of tool string problems during stations, The integration of the previous reservoir and the wellbore information with the help of customized planner and

field experience data base helps to define the more convenient tool string, its deployment method and sampling process technique: flow rates; need of segregation technique, low shock or reverse low shock, high flow area – XLD probe, dual packer, CHDT, OHDT, focused sampling probe, observer probe for detail pressure variations during the operation, etc. (Cañas et al.,2005, De Andre et al., 2005, Schlumberger (1996, 2005), Akram, A.H. et al, 1998, Zeybek, M., et al., 2001, Goode, P.A. et al, 1990, Pop, J.J. et al, Haddad, S., 2001, Mullins, O., et al., (2004,2005), Schlumberger (2005)).


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Figure 1. Recommended Fluid Sampling Process

Following we present some of the recent technologies that makes possible the down hole fluid analysis and

sampling in the previous mentioned reservoir and wellbore conditions.

2.1. Unconsolidated Formations

Unconsolidated sands are composed of saturating fluids, fines (fine scale solids interspersed in the matrix) and

sand grains, which have little or no cementation. These formations may fail as the result of processes such as drilling operations, rapid pressure changes and the setting of the testing tool’s probe or dual packer.

Flow Rate and Critical Draw Down Pressure Balance:

The origin of most sampling problems is a sudden pressure change and the associated surge of fluids. This “shock” to the formation can cause flow rates higher than the critical flow for sanding. These high flow rates are unstable and cause large drag forces on the sand grains. This flow rate mobilizes the sand grains and fines. The entry of sand into the Wireline formation testers (WFT) results in plugging flow lines, erosion of parts and can prevent proper operation of mechanical components in the tools. High flow rates will also promotes the migration of fines and emulsion generation. Fines tend to create a restriction to flow and can cause plugging and collapse of the WFT’s filter screen and gravel pack (Figures 2 and 3).

As described, extremely low flow rates are normally required for sampling highly viscous oils in

unconsolidated sands. Fortunately, oil of very high viscosity will often restrict invasion, which reduces clean-up volumes. However, other factors such as reservoir permeability, anisotropy, nearby upper and lower impermeable barriers and location of the WFT relative to the formation being sampled should be considered for optimum sampling processes (Cañas, J.A. et al 2005).


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Figure 2. Unconsolidated sandstone Figure 3. WFT pumping issues in unconsolidated

formation with viscous oils

Considering field experiences and detailed numerical modeling, high flow rates (10 cc/s) for consolidated rocks allow faster clean outs, (Fig. 4). However, high flow rates are prohibited in poorly consolidated formations due to the WFT plugging produced by critical sand migration (e.g. UCS < 500 psi). Even 2 cc/sec could be too much for a formation with a very low UCS (< 200 psi), see Fig. 5. The clean out process at low flow rates (0.5 cc/s), Fig. 6, is safer in poorly consolidated formations but usually is out off the normal operation time an operator is willing to run a WFT for sampling. Simulation in Figure 4 (high flow rate) and Figure 6 left (low flow rate) consider the same reservoir and fluid conditions for WFT comparison. In order to overcome this limitation, Schlumberger built and patented the fluid segregation technique -DhSEG- (Schlumberger, 2004), which could be integrated to the normal sampling operation to optimize its time with out affecting the fluid quality, Figure 6.

Figure 4. Water-cut prediction for a consolidated Figure 5. Weak sandstone instability at 2 cc/sec formation with 30 cps oil at 10 cc/sec flow rate – and 100 % Water-cut numerical simulation Segregation Technique (DhSEG):

The DhSEG technique basically consists of having a way to segregate, down hole the formation hydrocarbons (in 6 or 2 ¾ gal MRSC, or the 600 cc compensated pressure chamber MRSS); from the water filtrate (WBM) and collect such segregated clean formation fluid for further lab analysis. Optical fluid property sensors (MRFA) are used to


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monitor the segregation quality before transference to the single-phase sampling chambers in the Multi Sample module (MRMS) with the pump (MRPO), see Figure 6. The lab results have confirmed contamination less than 7%. It looks for rig time optimization since it would not be necessary to pump a large volume of fluid in order to clean up the formation fluid from the filtrate and makes feasible complex sampling operations such as viscous fluids.

Fig. 6. Water-cut prediction for a very weak formation during WFT sampling process of 300 cps oil viscosity at 0.5 cc/sec (left side plot) and the DhSEG technique (right side plot)

Optimized Flowing Area:

Other aspect to consider is the effective flowing area, because the direct relation ship between oil viscosity and draw down pressure. In this sense, field experience shows that Dual Packer WFT allows sampling oils with higher viscosity than Single Probes WFT in highly unconsolidated sands. This is because of the larger reservoir-wellbore contact area, lower pressure draw downs for similar flow rates and improved filter capability (Fig. 7).

There are conditions where the extra large diameter (XLD) probe could represent the optimum condition, as in the case of low to intermediate oil viscosities (< 60 cps) with saturation pressures well bellow the reservoir pressure (Pr-Psat > 800 psi) to keep single-phase conditions, and intermediate to high permeability consolidated formations.

Optimized Focused Sampling:

However, a recent option for faster clean out and contamination reduction is the new focused sampling probe (Weinheber, P., 2006), which has an effective total flowing area in the order of three times the large diameter probe and unique attributes to focus the native fluid through the inner flow line and the contaminated fluid thought the external (guard) flow lines (Fig. 8). It should overpass the range of the XLD probe for viscous oil sampling, which has limitations to sample single-phase and low contamination viscous oil with viscosities near 60 cps in weak formation, because the critical draw down limits associated with these formations. However, the final decision to use a WFT for sampling depends on a case-by-case analysis according with the process previously presented.

Figure 7. WFT effective flowing area (EFA) comparison Figure 8. Focused sampling probe


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Dual Packer, Probe and Mud Check Valves Filters (MCV):

Customized filters have been built for the dual packer MDT (Fig. 7 lower picture), single probe and MCV to reinforce the protection of these elements to fine migration, which is very common in viscous oil sampling from unconsolidated formations. As a result, the pressure drawdown is reduced to minimum values and mobilization of the sand particles during cleanup and sampling is avoided. The packers have remained set for longer hours with reduced tool sticking risk and provide long transient pressure buildup data capability for formation testing.

Low-Shock Sampling (LSS):

It revolutionized the sampling on wireline around 1997 in both sample recovery and quality of the samples when sampling near saturation pressure reservoirs where detailed control of draw down pressures are needed. In this sense it is equally valid for sampling unconsolidated formations where the draw down needs to be limit but to avoid sand production.

This technique uses the pump in the WFT string to “move” the fluid into the sample chamber against the hydrostatic pressure.

Reverse Low Shock Sampling (RLSS):

This is a unique attribute of the Modular Formation Dynamics Tester to avoid the 60-100 psi drawdown that could occurs inside the pumpout module and which is necessary to make the fluid to flow.

While the normal configuration for low-shock sampling is to have all the sample chambers on the downstream (high pressure) side of the pump, with the Reverse low shock technique this is changed, by putting the sample chambers upstream (low pressure side) of the pump. Reverse low-shock sampling will force the sample fluid into each bottle by pumping out the water behind the pistons of each sample chamber (Fig. 9). This technique allows for the same benefits with low drawdown as traditional low-shock sampling. In addition, reverse low shock will make feasible to sample in tough environments, reduce the emulsion generation risk and prevents scavenging of H2S in the pump section. The sample should be the same as optical fluid analyzers say it is.

Additionally to the RLSS benefit of handling lower draw downs, its attribute of forcing the native fluids into the sampling bottle before the fluids pass through the pump, make it an effective method for sampling sour gases, because the H2S scavenging reduction thanks to the shorter flow path.

Extra High-Pressure Displacement Unit (XHPDU):

It refers to the super low displacement pump to be able to pump flow rates in the order of 0.3 cc/sec to sample formations with UCS bellow 500 psi. Smaller flow rates can be obtained with the Flow Control Module too; however the smooth operation of the XHPDU, linked with the dual packer or XLD probe and DhSEG technique have allows to sample very high viscous oils (> 3000 cps). In these conditions is recommended to run two pumps for redundancy and guaranty long operations (one above and other down the probe or dual packer); slow clean out or multi-stations .

Observer Probe Monitoring:

The well known combinations of Dual Packer and Vertical Probe, two vertical probes or the dual probe plus a vertical probe, with usual separation distances of 2 - 7, 2.44 and 0.7 meters respectively, that has been widely used for reservoir anisotropy or vertical interference tests (VIT) by the industry in the last decade (Pop, J.J et al 1993, Onur, M., et al, 2002), has proved to be an effective tool combination for formation failure diagnostic during WFT pump out operations, through the real time monitoring of the differential pressure in the testers (interference at the observer probe is affected before the sink plugs). It allows adequate adjustment in the flow rate to prevent complete formation collapse near the sink station, which means aborting the test and creating potential conditions for tool stuck (see Fig.10).

Reservoir Single-phase Sampler - MRSS:

This high storage capacity multisampler consists of three chambers of 600 cc each. Additionally, these chambers allow taking validation samples of 100 cc for field confirmation of fluid quality with out affecting the main sample (600 cc). These capabilities make MRSS to play a key role in techniques such as DhSEG to optimize sampling operations and reduce operational time. The high volume of this single phase fluid sampler module has allowed to sample 13.7 API oils, when this sampler is run in combination with modern down hole fluid analysis (DFA) sensors (LFA, CFA), the dual packer and XLD Probe and the high pressure displacement unit (super low flow rate pump). An analysis of these oils showed contamination between 0.8 and 1.9%. Even vertical interference test have been performed after the fluid sampling using the combination: dual packer and probe.

Downhole Fluid Analysis (DFA):

It has recently been established as a new technique to address fluid characterization and compartmentalization. In particular, the objective of an entirely new type of log, a continuous downhole fluids log, is being realized (Mullins,


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et al., 2005, Schlumberger, 2005). Optical spectrometry sensors (LFA, CFA) support the contamination monitoring of viscous oils in complex situations such as OBM (Oil based mud) by offering a real time presentation of water, oil and gas fraction, fluorescence, hydrocarbon composition (C1, other hydrocarbon gases (C2-C5) and hydrocarbon liquids (C6+) groups) and GOR. They can also be used to ensure single-phase fluids and estimate saturation pressure. Enriched field databases and continuous field and lab data integration allows the optimization of the fluid sampling quality and reservoir compartmentalization modeling (fluid scanning). Fig. 11 presents a recent DFA survey supporting a viscous oil characterization in an OBM environment as part of a sampling operation.

Figure 9. Reverse Low Shock Sampling Figure 10. Formation failure monitoring through VIT WFT configurations (field case with two vertical probes)

Figure 11. Viscous oil Downhole Fluid Analysis (DFA) in an OBM environment

The adequate integration of these technologies under the Fluid Sampling Process presented in this section have allowed to sample viscous oils above 3200 cps at reservoir conditions in South America and perform mini DST and VIT


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for detailed reservoir characterization. Additionally, the pressure pretests with the DFA process as part of fluid identification or samplings stations have allowed confirming the existence of biodegradation or compartmentalization phenomena in several reservoirs (Figures 12 to 15).

Fig. 12. Viscous oil sampling with Dual Packer (2750 cps) Fig.13.Conventional high viscous oil sampling MDT

DFA sensors

Fig. 14. Viscous oil sampling with Dual Packer (3200 cps) Fig. 15. Highly viscous oil sampling with MDT - DFA sensors 2.2. Tight Reservoirs (TR)

Often, more data are needed to evaluate a tight reservoir that is needed to evaluate a conventional reservoir. As

such, the operator needs to develop efficient static & dynamic integration processes that can be used to evaluate these reservoirs with the minimal logging suite. In this sense a detailed native fluid and flow parameters characterization is crucial to design the completion and stimulation strategies of this type for reservoirs. As pointed out by Holditch S. (2006), it is likely that more gas will be recovered by producing all the layers in a commingled fashion because the abandonment pressure is lower at any given economic limit when the zones are commingled vs. producing the zones one at a time in a multilayer system or productive zones that are separated in the reservoir by vertical flow barrier layers.

In this contest the WFT plays a key role for a fast and economical reservoir fluid and flow parameters scanning along the reservoir. Key aspects in this process, which include proper fluid sampling design activities (Fig. 1) in TR are:

- Availability of fast permeability indicators (magnetic resonance, etc) and invasion depth estimation to select the most adequate WFT for native fluid identification and sampling, - Integrate drilling gas information,


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- Representative temperature, formation and hydrostatic pressure information for tool and packers selection - A representative number of pressure pretests along the reservoir column is critical to support the previous two statements (fluid gradient & best mobility levels identification), - Wellbore conditions geometry and trajectory appraisal (multi-caliper and imaging logs), Note that the best mobility and borehole conditions levels should be chosen for successful sampling via WFT.

The idea is to get the cleaner single phase sample in lesser time. Depending on the formation & fluid properties and wellbore conditions, the options for sampling in low

permeability reservoirs are the Dual Packer, Cased or Open Hole Dynamic Tester (CHDT / OHDT), Quicksilver and extra large diameter probe (XLD probe).

Low permeability formation in the order of 0.6 mds has been sampled with the XLD probe (including effective pretests accomplishment). In general formations with draw down mobilities (DDM) above 5 md/cps and low native fluids viscosity could be sampled with the XLD Probe or the Quicksilver, combined with medium to low flow rate pumps; while for lower DDM the use of the Dual Packer or CHDT is preferable because high pressures draw down can affect the quality of the single phase and the operation itself.

The CHDT / OHDT is a probe tool with drilling capabilities to perforate a 6 inches hole (0,28 in diameter) perpendicular to the wellbore face; it gives a better reservoir contact and has a better condition for invasion clean-out during pump out operations and supercharge liberation in the case of mini tests.

The best sampling procedure in these formations where high draw down could affect the sample quality, are the low shock sampling or reverse low shock sampling for detailed control of draw down pressures to assure the quality of the samples when sampling near saturation pressure reservoirs. Additionally, it is necessary to consider the use of a pump for super flow rates (XHP DU – most common) or the Flow Control Module (MRCF-CA) for fluids such as wet gases, which could be near to the saturation pressure (dew point).

The position of the DFA sensors is quite important with respect to pump position in the string. In water based mud systems, one fluid analyzer needs to be at the high-pressure side of the pump, before the sample chambers. This will help us to properly identify fluid segregation (oil/water and gas) within the pump displacement unit and the time to open the sample chamber will be adjusted to capture the hydrocarbon slug within the chamber.

In case of sampling hydrocarbons in OBM systems the option is to include a compositional fluid sensor (e.g. CFA for C1, C2-C5, C6+ and CO2 monitoring, plus fluorescence and GOR) for detail validation of the contamination, native fluid characterization (scanning) and saturation point detection. In fact, it is an excellent option to have two fluid analyzers in the string to identify free gas or dew formation better (phase separation).

A pump out and down hole fluid analysis operation in a very low permeability formation (K ~ 0.1 md) drilled with OBM is presented in Figure 16. Because the very low permeability indicated by the magnetic resonance and additional information, it was decided to run a Dual Packer WFT as shown in Fig.17. It was located in the best resistivity zone but near the transition, where lower values of resistivity are not explained by other logs. The results indicated that the reservoir contains gas; after the entrance of OBM filtrate (green color in track 3), the optical and gas reflection sensor show the progressive gas (white color in track 3 and red color in track 2 respectively) and water entrance (blue color in track 3). However, after a 55 % increment in the flow rate there is an important increment of the water and the gas is blocked (see track 3 in Fig. 16 and flow rate in Fig. 17 – lower plot), while the filtrate contamination went bellow 8 %. Apparently the draw down pressure was enough to incentive water coning from the lower resistivity zone, in spite the upper gas zone look to have some free water too.

2.3. Naturally Fracture Reservoirs (NFR)

The presence of fractures often surrounded by an otherwise low-permeability matrix is a major oil-recovery issue. Similar conditions could be offered by the highly laminated reservoirs.

The wireline logging techniques to evaluate NFR evolved with the advent of resistivity and sonic imaging (Fullbore Formation Micro Imager and Sonic Scanner tools) that allows fracture detection and quantitative evaluation, and the capabilities of the Modular Formation Dynamics Tester to straddle fracture intervals (dual packer), identify fluids, take samples, and acquire data for transient pressure analysis of the interval. In this sense, fracture interpretation from image logs is enhanced when its results are calibrated with core and dipole sonic data (stoneley and anisotropy interpretation), setting the basis for rigorous productivity analysis (Barroso, A., et al., 2005).

In these highly heterogeneous reservoirs, the dual packer adds a new dimension to the reservoir evaluation and fluid sampling. An example is presented in Figure 18 (Ayan, C., 1998). In this operation a detail resistivity and sonic imaging analysis allowed to identify the breakouts, irregular caliper, fractures (presence and orientation) and none fractured sections. This supports the selection process of intervals for fluid sampling and testing. This information was integrated with the complete suit of open hole logs, PLT and DST data to elaborate a detailed micro and macro


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characterization of this big gas condensate reservoir, which has shown to be effective in the well completion schemes definition.

Fracture density and orientation is easily obtained from image logs. It is important to distinguish between natural fractures and induced fractures. At first, it was attempted to distinguish between natural and induced using a combination of character and orientation. However, it turned out that it is not possible to use orientation to distinguish between natural and induced fractures, especially when the natural fractures have more than one orientation. The orientation of the fractures as seen on image logs was verified by paleomagnetic orientation of fractures in core. In a few cases, it could be shown that the original fracture orientation was rotated in drag folds around faults. Although it was possible to rotate each fracture orientation back to its original position using dip orientation of bedding, that method was not employed since it is the actual orientation of fractures that should be used in the model. Today stress orientation is obtained from breakout analysis of dipmeter logs in order to estimate which fracture orientations are probably open in the reservoir.

Fig. 16. Pump out and Sampling in a tight formation Fig. 17. Dual packer operation in a tight formation - - Down Hole Fluid Analysis Monitoring Dual packer location and flow rate profiles

Fig. 18. Sampling in fractured formation – Dual Packer & Down Hole Fluid Monitoring


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Fig. 19. Selective Sampling and testing of a massive fractured formation with Dual packer and Vertical Probe 2.4. Handling difficult operational situations

Based on the requirements for fluid sampling operations, there are cases where the combination of the mentioned technologies is required to warranty representative fluid samples. In deep and/or complex wells (both offshore or land), we frequently have to run complex WFT strings that could present high risk of getting stuck. In order to minimize this risk we may need to run wireline jars, perform Logging While Fishing operations (LWF: wireline conveyance converted into drill pipe conveyance after getting stuck), (TLC Tough Logging Conditions) or Coil tubing log to be able to increase the maximum pull that can be applied to our tools downhole, well deviation, mud weight and zone depletion are decision factors to weight when choosing among the different methods for conveyance (Fig. 20). In the specific case of offshore operations, we need to log quite often rigs equipped with DP (Dynamic Positioning) Rigs and WMC (Wave Motion Compensator) to compensate for the tidal movement in order to not affect our depth control. Due to the complexity added to the job by these necessary systems it is important to understand how they work to integrate its performance to the WFT operation. When doing a TLC operation in a WMC rig there are many key issues that should be taken into consideration to guarantee that the operation will be performed in a safely manner. These include:

- Cable Side-Entry Sub (CSES) maximum depth - Distance of Pipe Joint to Bushing

- A slotted bushing can be very helpful - Constantly monitor DP position - For Sampling/Pre test jobs the annular could be closed, according to

local practices

Fig. 20. TLC illustration (drill pipe conveyed)

3. Conclusions 1. The field experience and analytical studies associated to this document illustrate the importance of an integrated appraisal process in the fluid sampling and wireline formation testing of complex reservoirs, and the benefits of such a process: highly viscous oils, sour gases, gas condensate and water in unconsolidated, naturally fracture or tight reservoirs drilled with WBM or OBM are the target of this process. This information is critical to the success of DST operations and adequate reservoirs productivity appraisal. 2. Cleanup time and contamination levels can be reduced by using a series of best practice techniques which include WFT tool, sampling level and flow rate / draw down selection as per formation stability, depth of invasion, viscosity ratio, anisotropy and location of the WFT in the formation.


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3. XLD probe represents a faster option for viscous oil sampling bellow 60 cps and the Quicksilver should help till 100 cps depending on the formation stability and saturation pressure. Unconsolidated formations with oils above 60 cps should be sampled using Dual Packer modules together with super low flow rate pumps (bellow 1 cc/sec). Oils above 3200 cps were sampled with WFT, using these practices. 5. The slow segregation phenomena in viscous oil fluids at low pumping rates favors the faster local clean out near the WFT in the first hours of pumping. The DhSEG technique takes advantage of this phenomenon by taking earlier samples and reducing the water-cut contamination level using the WFT for fluid segregation before capturing final samples. 6. The challenge of detailed reservoir characterization in heavy oil and deep water environment, deep naturally fractured reservoirs, none natural flowing and highly heterogeneous reservoirs is being competently overcome whit the support of the high vertical resolution of the WFT pressures testing, its pump out and fluid scanning capabilities.

5. Acknowledgment The authors would like to thanks Schlumberger to publish this paper and the continuous feedback and support from our clients, Data Consulting and Operations team; however, the applied integration methodology and conclusions put forward in this paper are the responsibility of the authors alone.

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BARROSO, A., et al., Integrated Approach For Naturally Fractured Reservoir Production Characterization, SPWLA, Mar del Plata, Nov. 2005. CAÑAS, J.A., LOW, S., ADUR, N., TEXEIRA, V., Viscous Oil Dynamics Evaluation for Better Fluid Sampling, SPE 97767, Nov. 2005.

De ANDRE, C., CAÑAS, J.A., LOW, S. Rigorous Approach for Viscous-Oil Productivity Forecast Before Well Completion”, SPE 94837, LACPEC, RJ, June 2005.

GOODE, P.A., THAMBYNAYAGAM, R.K.M. Analytic Models for a Multiple Probe Formation Tester, SPE 20737 presented at the 1990 SPE Annual Technical Conference and Exhibition, New Orleans, LA, Sept. 23-26.

HADDAD, S., CRIBBS, M., SAGAR, R., TANG, Y., VIRO, E., CASTELIJINS, K. Integrating Permeabilities from NMR, Formation Tester, Well Test and Core Data. SPE 71722, New Orleans, Louisiana, Sep., 2001.

HOLDITCH, S.A. Tight Gas Sands. Texas A&M U., JPT, SPE,. p.86-93, Jun., 2006. MULLINS, O., et al. Hydrocarbon Compositional Analysis In-Situ In OpenHole Wireline Logging. SPWLA 45th Annual Logging Symposium, Jun. 6-9, 2004.

MULLINS, O., et al. Coarse and Ultra-Fine Scale Compartmentalization by Downhole Fluid Analysis, SPE, IPTC 10034, Qatar, 21–23 November 2005.

ONUR, M., et al., Pressure-Pressure Convolution Analysis of Multiprobe and Packer-Probe Wireline Formation Tester Data, SPE 77343, Annual Technical Conference and Exhibition, San Antonio, Texas, Sep. 2002.

POP, J.J et al.: “Vertical Interference Testing With a Wireline-Conveyed Straddle-Packer Tool”, SPE 26841, SPE Annual Technical Conference and Exhibition, Houston, TX, Oct. 3-6 (1993).

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ibp1970 06 fluid sampling optimization process with ... · 1 msc, petroleum and reservoir engineer...

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