32 Oilfield Review

Step Change in Well Testing Operations

In exploration and appraisal environments, one way to gather data for well

productivity and reservoir characterization is through well or drillstem testing.

The acquisition of downhole well test data has recently been enhanced by the

development of an acoustic wireless telemetry system that gives operators access

to these data in real time.

Amine Ennaifer Palma GiordanoStephane VannuffelenClamart, France

Bengt Arne Nilssen Houston, Texas, USA

Ifeanyi Nwagbogu Lagos, Nigeria

Andy SooklalCarl WaldenMaersk Oil Angola AS Luanda, Angola

Oilfield Review Autumn 2014: 26, no. 3. Copyright © 2014 Schlumberger.For help in preparation of this article, thanks to Michelle Parker Fitzpatrick, Houston; and David Harrison, Luanda, Angola.CERTIS, CQG, InterACT, IRDV, Muzic, Quartet, RT Certain, SCAR, Signature and StethoScope are marks of Schlumberger.

By the time Edgar and Mordica Johnston per-formed the first commercial drillstem test in 1926, more than two dozen formation tester pat-ents had been issued. Before the Johnston broth-ers introduced their innovative methods, if oil did not flow to the surface, exploration wells were tested through bailing—lowering a hollow tube on a cable to capture a formation fluid sample—after casing had been set and cemented above the zone of interest. The brothers’ success led to the creation of the Johnston Formation Testing Company, which Schlumberger acquired in 1956.

Today, the most common drillstem tests (DSTs) are temporary well completions through which operators produce formation fluids while the drilling unit is on location. During DSTs, for-mation fluids are typically produced through drillpipe or tubing to a test separator or other temporary surface processing facility, where the fluids are metered, sampled and analyzed.

Drillstem tests focus on acquiring various types of data. A descriptive test may concentrate on acquiring downhole reservoir fluid samples and pressure data from a shut-in well; a produc-tivity test may focus on identifying maximum flow rates or determining reservoir extent. In explora-tion and appraisal wells, the primary well test objectives focus on well deliverability, skin, fluid sampling, reservoir characteristics and identification of reservoir extent and faults.1 In development wells, the objectives are typically linked to measurements of the average reservoir pressure and skin and determination of reservoir characteristics.

Well test operations comprise cycles of well flow and shut-in while bottomhole pressures (BHPs) are monitored. Reservoir engineers apply

these data to make early predictions about res-ervoir potential through a process known as pressure transient analysis, in which the rate of pressure change versus time during a shut-in and drawdown cycle is plotted on a logarithmic scale. The resulting plots indicate reservoir response patterns that can be associated with specific reservoir models using generalized type curves; the curves help determine reservoir characteristics such as skin, permeability and half-length of induced fractures.

The shut-in mechanism must be as close as possible to the point at which formation fluids enter the wellbore to eliminate the influence of wellbore storage on the downhole data. Wellbore storage refers to the volume of fluid in the well-bore that may be compressed or expanded, or to a moving fluid/gas interface as a result of a production rate change. Wellbore storage may exhibit complex behavior below the point of shut-in, such as phase segregation, which can hinder true reservoir response by mixing with or masking reservoir pressure transients.2 A crucial part of the pressure transient analysis is distin-guishing between the effects of wellbore storage and the interpretable reservoir response in the early stages of the test.

At various points during the test, technicians may capture representative samples of formation fluids through the test string; fluid capture may be performed using dedicated inline sample car-riers equipped with trigger systems or by deploy-ing through-tubing wireline-conveyed samplers. The samples are then sent to a laboratory for detailed PVT analysis in a process that may take several months.

1. Skin is a term used in reservoir engineering theory to describe the restriction of fluid flow from a geologic formation to a well. Positive skin values quantify flow restriction, whereas negative skin values quantify flow enhancements, typically created by artificial stimulation operations such as acidizing and hydraulic fracturing.

2. Al-Nahdi AH, Gill HS, Kumar V, Sid I, Karunakaran P and Azem W: “Innovative Positioning of Downhole Pressure Gauges Close to Perforations in HPHT Slim Well During a Drillstem Test,” paper OTC 25207, presented at the Offshore Technology Conference, Houston, May 5–8, 2014.

3. Kuchuk FJ, Onur M and Hollaender F: Pressure Transient Formation and Well Testing: Convolution, Deconvolution and Nonlinear Estimation. Amsterdam: Elsevier, Developments in Petroleum Science 57, 2010.

Autumn 2014 3333

By deploying logging-while-drilling tools such as the StethoScope formation pressure-while-drilling service, engineers may ascertain initial information about reservoir properties, formation fluid types and producibility. This information is often coupled with wireline log analysis and for-mation pressure and sampling data after the well has been drilled through the section of interest. In exploration and appraisal wells, these esti-mates may be associated with some uncertainty, and the reservoir parameters can be confirmed only by monitoring the reservoir under dynamic conditions such as is done with DSTs.

Drillstem tests provide complementary data for reservoir and formation fluid characterization and for predicting the reservoir’s ability to pro-duce. Of all the data that operators depend on to design well completions, these data include the least amount of uncertainty and the deepest radius of investigation.3 The duration, producing time and flow rate of a DST provide a deeper investigation into a reservoir than do other res-ervoir evaluation techniques. As a consequence, well testing provides the bulk of the information engineers need to design well completions and production facilities.

Although more efficient, reliable and robust, the primary components of DST assemblies today are similar to those deployed by the Johnston Formation Testing Company in the 1930s. These components consist primarily of four types of devices:• packers to provide zonal isolation • downhole valves to control fluid flow • pressure recorders to facilitate analysis• devices to capture representative samples.

Changes to test systems over time have been confined mainly to the addition of auxiliary components such as circulating valves, jars, safety joints and other devices aimed at reduc-ing the time required to recover from a stuck testing string or to provide options for killing a well. In recent years, service companies have done much to reduce uncertainty and costs associated with well testing while increasing safety and efficiency. A significant step in this progression includes the Quartet downhole res-ervoir testing system.

The Quartet testing tool allows operators to perform the four essential functions of a DST assembly—isolate, control, measure and sam-ple—in a single run. The system includes the CERTIS high-integrity reservoir test isolation sys-tem, the IRDV intelligent remote dual valve, Signature quartz gauges and the SCAR inline independent reservoir fluid sampling tool.

34 Oilfield Review

The CERTIS isolation system provides pro-duction-level isolation with single-trip retriev-ability. It includes a floating seal assembly to compensate for tubing movement during well testing and eliminates the need for slip joints and drill collars (below). The IRDV dual valve is an intelligent remotely operated tool that allows

operators independent control of the tester and circulating valve via commands transmitted by low-pressure annular pulses (below). Signature gauges that have ceramic electronics boards provide high-quality pressure and temperature

measurements at the reservoir (next page, top left).4 The SCAR inline independent reservoir fluid sampling tool collects representative reser-voir fluid samples from the flow stream (next page, top right).

The accuracy of reservoir property analysis and the degree of reservoir understanding are heavily dependent on the quality of pressure measurements acquired downhole; obtaining accurate measurements hinges on metrology and its parameters.

Cornerstone of Pressure Transient Analysis Metrology is the science of measurements based on physics. Technicians use the methods of metrology to ascertain that sensors are properly calibrated to specified or technical parameters (next page, bottom). In the case of pressure gauge metrology, static parameters include the following: • Accuracy is the algebraic sum of all the errors

that influence the pressure measurement. • Resolution is the minimum pressure change

that can be detected by the sensor and is equal to the sum of sensor resolution, digitizer resolu-tion and electronic noise induced by the ampli-fication chain. Therefore, when determining gauge resolution, engineers must consider the associated electronics and specific sampling time. The resolution of the interpreted range of investigation, or transient drainage radius, depends on the resolution of the gauge. Gauge metrology could impact important decisions operators make in evaluating reservoir size and extent, which is a key objective of well testing interpretation.5

• Stability is the ability of a sensor to retain its performance characteristics for a relatively long period of time and is the sensor mean drift in psi/d at a specified pressure and tempera-ture. The levels of stability include short-term stability for the first day of a test, medium-term stability for the following six days and long-term stability for a minimum of one month.

• Sensitivity—the ratio of the transducer output variation induced by a change of pressure to that change of pressure—is the slope of the trans-ducer output curve plotted versus pressure.

Dynamic parameters include the following:• Transient response during pressure changes

is the sensor response recorded before and after a pressure variation while the tempera-ture is kept constant.

• Transient response during temperature changes is the sensor response monitored under dynamic temperature conditions while the applied pressure is kept constant. This param-

Stinger seal

Sealbore

Release ring

Slips

Bypass

Ratchet lock

Hydraulicsetting mechanism

Rupture disc

Stinger release

Stinger

Seal element

Perforating guns

> Isolation system. The CERTIS system’s hydraulic setting mechanism is activated by applying pressure to a rupture disc; setting does not require string rotation or mechanical movement. To unset the system, an upward force disengages the ratchet lock and shears the retaining pins in the release ring, which allows the slips to relax and release the system. Continued pulling reopens the bypass, which eliminates swabbing while pulling the packer out of the hole. The stinger floats inside the sealbore, which compensates for string movements caused by temperature changes. The system allows gauges to be positioned below it in the test string. Tubing-conveyed perforating guns can be suspended below the body.

>Remote dual valve. The IRDV intelligent remote dual valve combines a test valve and a circulating valve that may be cycled independently or in sequence. The test valve, the primary barrier during the well test buildup period, is activated through wireless commands or low-pressure pulses. Wireless commands facilitate the independent operation of both valves without interfering with the operation of other tools in the test string. In the open position, the circulating valve allows flow between the tubing and annulus. Low-pressure pulses are detected by the pressure sensor, and the electronics confirm the received command by comparing it with those in a library stored in the tool memory. The IRDV valve may be configured to provide wireless feedback, confirming command reception. The activation of both valves is initiated by battery power, which is augmented by a hydraulic fluid circuit that discharges fluid from the atmospheric chamber into the hydrostatic chamber when the valve is operated.

+-+-+-

Circulatingvalve (closed)

Atmosphericchamber

Test valve (open)

Hydrostaticchamber

Pressure sensor

Battery

Autumn 2014 35

eter provides the stabilization time required for a reliable pressure measurement for a given temperature variation.

• Dynamic response during pressure and tem-perature changes is the sensor response recorded before and after a change in both pressure and temperature.

Pressure data help engineers develop infor-mation about the size and shape of the reservoir

and its ability to produce fluids. Pressure tran-sient analysis is the process engineers use to convert these data to useful information. During this process, they analyze pressure changes over time, particularly those changes that are associ-ated with small variations in fluid volume.

During a typical well test, a limited amount of fluid is allowed to flow from the formation while the pressure measurement at the sandface is acquired along with downhole and surface flow rate measurements. After the production period, the well is shut in while downhole pressure data acquisition continues during the buildup.

4. For more on Signature gauges: Avant C, Daungkaew S, Behera BK, Danpanich S, Laprabang W, De Santo I, Heath G, Osman K, Khan ZA, Russell J, Sims P, Slapal M and Tevis C: “Testing the Limits in Extreme Well Conditions,” Oilfield Review 24, no. 3 (Autumn 2012): 4–19.

5. Kuchuk FJ: “Radius of Investigation for Reserve Estimation from Pressure Transient Well Tests,” paper SPE 120515, presented at the SPE Middle East Oil and Gas Show and Conference, Bahrain, March 15–18, 2009.

> The Signature quartz gauge. The Signature gauge consists of a sensor, electronics section and battery. The sensor includes a multichip ceramic module (not shown).

Battery

Electronics

Sensor > Downhole fluid sampler. The SCAR inline independent reservoir fluid sampling tool (left ) captures representative, contaminant-free, single-phase fluid samples directly from the flow stream close to the reservoir. The tool houses the single-phase reservoir sampler (right ). Using a rupture disc triggering mechanism, initiated by applied annular pressure or through wireless command, the sampler can be activated to open a flow channel to capture a sample. The single-phase reservoir sampler has an independent nitrogen charge to ensure each sample remains at or above reservoir pressure. When the triggering mechanism is activated, reservoir fluid is channeled to fill a sample chamber bounded by pressure compensation fluid. The compensation assembly comprises the nitrogen precharge, pressure compensation fluid and buffer fluid, which ensure that the sample chamber slowly provides enough volume to capture the reservoir fluid without altering its properties.

Rupture disctrigger

Buffer fluid

Nitrogen

Pressurecompensationfluid

Pressurecompensationfluid

Reservoirfluid

Single-phasereservoirsampler

> Gauge metrology parameters.

Static

Gauge Metrology Parameters

Accuracy

Dynamic

Resolution

Stability

Transient response during pressure changes

Transient response during temperature changes

Dynamic response during simultaneous pressure and temperature changes

Sensitivity

36 Oilfield Review

The downhole gauges that capture the reser-voir response during the well test must be highly accurate, but high accuracy is difficult to achieve because of the complex wellbore environment. During well tests, fluid dynamics and thermal and mechanical string effects impact tool response.

The technology used to capture pressure data has evolved considerably over time. In the 1930s, operators deployed mechanical gauges, which provided resolution of about 35 kPa [5.1 psi].

These gauges operated by recording the displace-ment of a pressure sensing element on a sensitive surface, which was rotated by a mechanical clock, thus providing a pressure versus time mea-surement. The data were digitized manually from the pressure-time chart.

Following improvements in electronics design and reliability led by the Hewlett-Packard Company, electronic gauges were introduced to the oil industry in the 1970s. Development of sta-ble electronic gauges with higher levels of accu-

racy progressed rapidly, and by the turn of the century, two main types dominated the industry.

Strain gauges were the first electronic gauges used widely in the oil industry. They operated on the principle of a resistance circuit placed on a pressure sensitive diaphragm. The change in length of the diaphragm in response to pressure altered the balance of a Wheatstone bridge cir-cuit. These strain gauges were capable of 0.7-kPa [0.1-psi] resolution, which may not be sufficient to resolve reservoir properties.

Vibrating quartz pressure sensors, developed in the 1970s, signaled a significant shift in the quality of downhole measurements in terms of metrology. Because of their superior metrological characteristics, quartz gauges have become the standard for downhole pressure and temperature acquisition although their accuracy may be affected by sudden changes in downhole temper-ature and pressure. Quartz sensors use the piezo-electric effect to measure the strain caused by pressure imposed upon the sensing mechanism. The frequency of vibration in relation to pressure changes is measured and converted to digital pressure measurements. The high frequencies of quartz sensors enable measurement of high- resolution pressure changes and rapid sensor response. Typical resolution of quartz gauges is 0.07 kPa [0.01 psi]. Today, the Schlumberger Signature CQG gauge, using a proprietary com-pensated quartz gauge—the CQG crystal—is able to distinguish pressure measurements as small as 0.021 kPa [0.003 psi] (left).

Signature gauges may be deployed in reser-voir tests at temperatures up to 210°C [410°F] and pressures reaching 200 MPa [29,000 psi]. They may be deployed in real-time or memory mode as part of the test string and are contained within gauge carrier mandrels able to hold up to four gauges each. Numerous carriers can be placed in the test string above and below the CERTIS isolation system.

The challenge of downhole measurements is not limited to the harshness of ambient condi-tions; three major sources of uncertainty affect downhole pressure measurements during well testing. Uncertainties in gauge resolution and accuracy, which are typically characterized as functions of the magnitude of pressure and tem-perature changes downhole, may introduce errors. In addition, uncertainty in the condition of the environment may induce error.6 For exam-ple, during the test flowing period, a gas bubble close to the gauge may burst and create high-fre-quency noise that is of the same order of magni-tude as the gauge accuracy and several times larger than the gauge resolution. If the pressure

>The impact of high resolution on data quality. Analysts can use high-resolution measurements (top ) acquired using a Signature gauge to deliver a clear interpretation of the pressure data. High-quality pressure data (middle, green) result in a pressure derivative curve (red) that is easily discernable and from which reservoir engineers can identify various pressure regimes during buildup. A low-resolution measurement (bottom) may deliver an uninterpretable dataset.

100

10

1

0.1

0.01

0.0010.0001

Pres

sure

, psi

0.001

10,000

1,000

00.0001

Pres

sure

, psi

Time, s

0.04

0.03

0.02

0

0 10 20 30 40 50 60 70 80 90 100 110 120

0.01

Pres

sure

, psi

Time, h0.001 0.01 0.1 1 10 100

Time, h0.01 0.1 1 10 100

Autumn 2014 37

changes quickly, and the sampling rate is rela-tively slow when this occurs, separating high-fre-quency noise from measurements is difficult. A similar situation arises if phase segregation of small quantities of water and gas in the well efflu-ent occurs.

With the introduction of quartz gauges, the parameters of pressure gauge metrology were improved significantly. However, experts recog-nized that the value of well tests was often impacted by the fact that data were inaccessible until after the tests were complete. To address this shortcoming, they developed a system that allows operators to monitor the progress of a well test as the test proceeds by delivering the down-hole pressure and temperature data to the sur-face in real time. With insights provided by these data, coupled with real-time downhole control, operators would then be able to alter ongoing tests to meet their objectives.

Real-Time Data, Real-Time DecisionsTo reduce the uncertainty associated with some well and reservoir parameters, engineers typi-cally begin a well test design by defining the objectives of the test (above). The acquisition of wireless real-time bottomhole pressure and tem-perature data gives operators the ability to man-age both the well and reservoir uncertainties, make adjustments during the test and exercise a measure of control over operational and cost challenges associated with traditional DSTs.

The sequence and duration of well test opera-tions are based on initial data obtained from vari-ous sources, including petrophysical logs and core analysis. Historically, well tests are based on a design-execute-evaluate cycle, in which techni-cians design and execute the tests to acquire downhole data for evaluation and capture fluid samples for laboratory analysis.

Downhole data are most frequently acquired using electronic gauges in memory mode, which do not provide operators with real-time feedback to validate pretest assumptions, to verify that objectives are being achieved or to modify the tests during execution. As a consequence, techni-cians typically execute the well test program regardless of reservoir response. This can result in unnecessary steps, prolonged tests, missed opportunities and even damage to the reservoir. That the pretest assumptions are wrong or the test is failing to meet objectives is often realized only after the test has been concluded and the memory data have been analyzed.

The industry has made attempts to correct this shortcoming by using surface readout (SRO) systems. These SRO systems deploy electric line tools to recover downhole data from electronic memory gauges that are run as part of the DST toolstring. The data download is typically per-formed toward the end of the test, which limits any modification of the operation to managing the remainder of the well test operation and does little to improve the overall operational sequence.

The practice of deploying electric line tools has become increasingly unpopular with opera-tors in expensive deepwater projects. Operators are concerned that the electric line cable may become snagged or part when it crosses valves. The efficiency of managing well test operations through electric line data acquisition is also lim-ited because it is typically performed only during nonflowing periods; electric line toolstrings are at risk of being forced up the hole when the well is flowing.

To address these limitations, Schlumberger engineers developed the Muzic downhole wire-less system (left). The Muzic system is designed

6. Onur M and Kuchuk FJ: “Nonlinear Regression Analysis of Well-Test Pressure Data with Uncertain Variance,” paper SPE 62918, presented at the SPE Annual Technical Conference and Exhibition, Dallas, October 1–4, 2000.

> A downhole reservoir testing system enabled by Muzic wireless telemetry. A network of acoustic repeaters, attached to the tubing using a system of clamps, enables remote interrogation of downhole gauges or tools with feedback via computer terminal at the rig. Two repeaters installed in each numbered node supply horizontal redundancy; one repeater is always on standby. Vertical redundancy is provided by repeaters able to communicate across twice the normal spacing between repeaters, which is usually 305 m [1,000 ft].

IRDV valve

Gauge carrier,Muzic wirelesssystem withSignature gauges

Gauge carrier,Muzic wireless

system withSignature gauges

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

192021

Repeaters

Seabed

SCAR sampler

Tubing

Flowhead Reeler

Interface box

Surface PC

Hanger

CERTISisolation system

> Types of well tests, test objectives and acquired data. Two types of tests—descriptive and productivity—provide a variety of downhole data. Descriptive tests seek information about well and reservoir characteristics, whereas engineers typically use productivity tests to understand the producing capacity, extent and drive mechanism of a reservoir. Both types require bottomhole pressure, bottomhole temperature and surface flow rates. Sequence and duration of individual flow periods differentiate the test types.

Type of Test Test Objectives Acquired Data

Descriptive Well characteristics Bottomhole pressure and temperature

Productivity Reservoir extent and drive mechanism Bottomhole pressure and temperature

Inflow performance ratio (combined well and reservoir) Surface flow rate

Reservoir characteristics (average reservoirpressure, permeability thickness, storativity ratioand interporosity flow coefficient)

Surface flow rate

Communication between wells and reservoirs(interference and multizone tests)

38 Oilfield Review

to be embedded into the Quartet DST string. The system interfaces with the Quartet reservoir test-ing system to facilitate interactive well testing operations in which the operator has direct access to downhole data in real time and is able to control downhole tools through wireless com-mands. The distributed digital wireless telemetry system uses an acoustic wave generated in the test string to transmit information.

The acoustic network is composed of a series of tools clamped on the outside of downhole test tub-ing (left). Each tool acts as a repeater and can transmit or receive an acoustic signal as well as allow control of downhole tools through wireless commands. By initiating real-time changes to the proposed testing program, operators can derive the maximum value from each testing operation.

Digital data are relayed from one repeater to the next in either direction on their way to their final destination. In the bottomhole assembly, the network interfaces either with downhole pressure gauges for data acquisition or with downhole tester tools (tester valve, circulating valve and sampler) to issue commands and verify tool status. This interactive platform also opens the possibility to expand the scope of reservoir testing to access previously inaccessible parts of the well for instrumentation and tool control.

The signal processing techniques used for downhole digital data transmission are similar to methods employed in other wireless communica-tions. However, successful wireless transmission is affected by many things, including pipe or tub-ing effects, ambient noise and electronics and battery limitations.

For acoustic propagation, tubing is a complex medium; its effectiveness in propagating acoustic waves is hampered by noise, attenuation and dis-tortion. For example, each time an acoustic wave goes through a tubing connection, it generates an echo. The series of echoes generated by crossing multiple joints are canceled by advanced signal processing techniques to achieve point-to-point communication. In addition, because the wireless telemetry system relies on acoustic propagation, any increase in ambient noise conditions down-hole can adversely impact transmission.

Additional engineering challenges arise from the low-power electronics required for long dura-tion battery operation. This low-power require-ment limits the choice of downhole processors and impacts the available processing power. To address these challenges, a specific network pro-tocol was developed that manages and optimizes communication through a repeater network.

>Network architecture of the Muzic wireless system. The Muzic wireless network is based on acoustic clamp-on style repeaters (left ) attached to tubing. The transducer generates an acoustic signal (red) encoded with digital information. Bidirectional acoustic energy travels the length of the pipe and is transmitted from each repeater to adjacent repeaters until the signal reaches the user at the surface. With such a series of repeaters, a network architecture (right ) can be established in which transmitting nodes (R) send and receive information from transmitting hubs and sensing or actuating end nodes (E). End nodes are points of interest for the surface user and include sensors to acquire measurements or actuators to control devices.

Clamp

Surface repeaterS

RepeaterR

End nodeE

Bidirectionalacoustic message

Piezoelectrictransducer

Acoustic message

Productiontubing

S

R R

R R

R R

R R

R R

R R

R R

E EE E

R R

R R

R R

R R

E EE E

E

>Comparing Signature gauge real-time data with memory data. Pressure data obtained by a Signature quartz gauge and transmitted wirelessly in real time are a nearly perfect match with data downloaded from memory during a pressure transient well test offshore Indonesia for Total E&P. The quartz gauges transmitted real-time bottomhole pressure and temperature data to the surface without interruption for almost seven days. These data allowed pressure transient analysis to be performed in real time and facilitated the validation of the ongoing well test operations versus the Total E&P Indonesia test objectives.

Pres

sure

and

pre

ssur

e de

rivat

ive

Time

Pressure

Pressurederivative

MemoryReal time

Autumn 2014 39

The Muzic system makes possible a new work-flow for real-time testing operations. A decision tree within this workflow includes risk assess-ment, test planning, data validation, quality assurance and quicklook validation of data dur-ing the execution phase. This process allows real-time decisions and adjustments to the testing plan while the test is underway.

A Real-Time Interpretation Workflow In traditional well testing operations, engineers design, prepare and execute the test and inter-pret the acquired data in sequence. In this “post-mortem” approach to reservoir characterization, insight obtained during data analysis does not impact the original design or execution phases, and the interpretation usually takes place after operations are concluded.

The availability of downhole data and tool sta-tus information in real time from technologies such as Muzic wireless telemetry represents a significant shift from the sequential approach. Feedback from the reservoir is immediate and available during the execution phase, allowing the operator to modify the test sequence and operation while the test string is still in the well. Real-time information about the condition of the wellbore and status of downhole tools consider-ably impacts operational efficiency and gives the operator confidence in the validity of the mea-surements (above right).

Introduction of real-time monitoring into the standard well test workflow reduces overall costs and rig time because the process is driven by actual reservoir responses and not by generally accepted practices and estimates (right). Any erroneous operational steps can be immediately identified and remedied, eliminating uncertain-ties and the costs of repeat operations as a result of inconclusive operational data.

Total E&P planned an exploration test of a 45° deviated well offshore East Kalimantan, Indonesia. The target zone was at 3,200 m [10,500 ft] MD with a bottomhole pressure of 25,000 kPa [3,600 psi] and a bottomhole temperature of 118°C [244°F].

The operator’s test objectives were to analyze the downhole pressure transient data and obtain initial estimates of key reservoir properties such as pressure, skin, permeability thickness and boundaries. A solution was designed around Muzic wireless telemetry interfacing with high-resolution Signature pressure gauges. The gauges, which proved to provide data that matched nearly perfectly with data gathered using memory gauges, transmitted downhole pressure and tem-perature for almost seven days (previous page, bottom). This continuous flow of data allowed

engineers to optimize flow and maintain reservoir conditions below depletion during testing. The reservoir engineer was also able to perform real-time interpretations of pressure transient data and thus validate that test objectives were being

met. Because the engineers were able to deter-mine the test objectives had been achieved as the test was proceeding, they could shorten the flow-ing period without fear of losing valuable pressure transient data.

> A real-time dataset overlaid on a memory dataset. In this example, data captured in memory mode (green) and real-time data (red) track perfectly. Data captured in memory mode can be accessed only when they are downloaded after the test is ended. Wireless-enabled reservoir testing, however, allows operators to observe pressures in real time and make decisions accordingly. Information that operators may derive from real-time test data and use to make decisions include tubing conditions while running in the hole (1), underbalance before perforation (2), connectivity after perforation (3), progress of cleanup and flowing periods (4) and buildup (5, blue shading). The flow rate (blue curve) is visible in real time throughout the test. Real-time measurements ceased when the operator began to pull out of the hole after almost seven days.

Pres

sure

, psi

Rate

, bbl

/dTime, d

8,000

7,000

6,000

5,000

4,000

3,000

2,000

1,000

1,250

2,500

0

00 1 2 3 4 5 6 7 8 9

Memory gaugeReal-time pressure

15

2

3

4

> A workflow for integrating the test design, execution and interpretation sequence in real time. Muzic wireless telemetry and InterACT collaboration software enable real-time interpretation and analysis for use in updating the geologic model and refining the transient analysis and eventual final reservoir model. The integration process includes information from the geologic model (1) used in test equipment selection (2) and test design (3). Because real-time bottomhole data are available during the test (4), the test results are continuously compared with the initial design expectation, and this output (5) helps in refining the final interpretation (6). This process continues iteratively for each flow period and results in a model with least uncertainty for the reservoir engineer. (Adapted from Kuchuk et al, reference 3.)

Geologic model

Test design

Real-time wellsite or remote-site interpretation

Final interpretation andvalidation model, verification

and uncertaintyOperation and

data acquisition

Hardwareselection

12

3

4 6

5

40 Oilfield Review

Petrobras engineers working in a presalt envi-ronment in the Santos basin offshore Brazil sought to obtain real-time data at the surface during a deepwater well test and to eliminate the wireline run typically required to acquire such data. Schlumberger and Petrobras engineers chose to deploy wireless-enabled Signature gauges in the well, which is in 2,000 m [6,600 ft] of water 250 km [155 mi] off the coast of Brazil. The Muzic wireless telemetry system and pres-sure and temperature gauges enabled for wire-less communication were run in the well. This configuration permitted engineers to receive data during flow and shut-in periods, to monitor cleanup efficiency in real time and to obtain key reservoir information before the end of the test (left). As a consequence, reservoir engineers were able to observe the pressure transient after perforation gun detonation to confirm dynamic underbalance.

Petrobras and Schlumberger engineers were also able to confirm downhole valve status, com-pute productivity as the well was flowing, confirm that sufficient data were acquired during the ini-tial and main buildup periods, eliminate a wire-line run and establish the reservoir pressure after the initial postperforating flow period (below left).

A common challenge in well test operations is managing the duration of the buildup period. Test operators often calculate a buildup period as an integer multiple of the flowing period duration. By accessing the actual downhole pressure response in real time during the buildup period, engineers are able to determine that the desired reservoir response has been achieved and vali-dated sooner than would be the case using the multiple, thus saving the operator hours of rig time. Conversely, if the reservoir response objec-tive has not been met, the test can be extended.

The overall efficiency of the operation is improved because downhole tool status can be verified at each step of the program. Important decisions about the progress of the test can be made with clear understanding of the reservoir response from downhole pressure conditions, which makes the overall operation safer. Using wireless tool activation also takes less time and requires fewer operational steps than do tradi-tional pressure activation methods. Real-time data are important for characterizing the reser-voir with the least possible uncertainty. The Muzic system enables remote interpretation through data sharing and collaboration software.

Based on a geologic model, the well test is designed and gauges and DST tools are selected to meet certain operational and acquisition criteria.

> Real-time productivity index mapping during well testing. Using the Muzic system, the operator tracked the productivity index during flow on several choke sizes.

Prod

uctiv

ity in

dex

Cleanup Second flow Third flowFirstflow

Firstbuildup

Secondbuildup Ch

oke

size

Time, d0 1 2 3 4 5 6 8 9 107

Productionlogging

toolrigup

Real-time productivity index Choke size

> Obtaining critical data in real time. The overlap of real-time and memory data demonstrates the accuracy of real-time data and their capability to provide sufficient insight into operational events, even though the real-time data sampling is less dense than memory mode sampling. An inset from a separate test shows TCP gun detonation data (left ); the sharp decrease followed by a sharp increase in pressure confirms in real time the postperforation flow of reservoir fluid into the wellbore. An inset from a separate test showing pressure response during the main pressure transient test (right ) demonstrates that the volume of data captured is adequate for detailed analysis, such as productivity index determination and pressure transient analysis, during flow and buildup periods.

Time

Tubing-conveyed perforating (TCP)gun detonation

Main pressure transient test

BHP

Real-time bottomhole pressureMemory bottomhole pressureReal-time annulus pressure

Memory annulus pressureReal-time bottomhole temperatureMemory bottomhole temperature

Autumn 2014 41

During the operation, the downhole pressure and surface rate data acquired by the system are vali-dated in real time, and QA/QC can be performed immediately. Engineers can use these data for quicklook interpretations and to determine well and reservoir parameters. The initial reservoir model may then be updated in real time with the information from the well test to generate a new interpretation model, verified with less uncer-

tainty. The process is multidisciplinary and dynamic; results from interpretation and analysis can be used to modify earlier assumptions in an iterative fashion and continuously generate a clearer picture of the reservoir.

Maersk Oil drilled an exploration well offshore Luanda to acquire data that would confirm the presence of hydrocarbons in the target formation. The well was drilled into oil-bearing sandstones;

the primary target was at a depth of approxi-mately 5,000 m [16,000 ft] in water depth of 1,462 m [4,797 ft].

Downhole gauges enabled by Muzic wireless telemetry transmitted data successfully through-out the test. The operator was able to verify the underbalance prior to perforating, establish initial reservoir pressure after perforating, verify the sta-tus of the downhole tools during the test, optimize the cleanup period by monitoring sandface pres-sure, reduce duration of buildup and confirm that samples were being taken in ideal conditions.

The RT Certain real-time test collaboration service brought reservoir experts at the rig in Luanda and in Copenhagen, Denmark, together in a virtual environment. A software platform enabled wellsite data transmission and interpre-tation tools that allowed experts to make the right decisions on site and from remote locations. This integrated system also helped ensure sufficient data were collected to complete a successful pres-sure transient well test.

The wireless downhole testing system saved 28 hours of rig time, about US$ 1.5 million in rig spread costs, while acquiring sufficient data for key reservoir property estimation (left). A com-parison of memory data from the gauges retrieved at the surface with the real-time data used for interpretation during the test validated the deci-sions made during the operation.

The Future of Well TestingEngineers have long recognized the value of DSTs but in certain circumstances have had to make compromises between quality data, costs and risk. Real-time wireless telemetry addresses those compromises by providing a means to cap-ture real-time data throughout the test, remotely activate downhole tools and isolate zones of interest efficiently without permanent packers and the need to collect reservoir fluid samples at specified times. Most importantly, unlike in the past, engineers can be certain they have achieved test objectives before the test is ended.

The future of real-time well testing goes beyond transmitting data to include the actuation of multiple devices in the DST string using this same wireless backbone. The immediate reward for these expanded capabilities will be measured in saved time, saved capital and improved ulti-mate hydrocarbon recovery as a result of develop-ment designs and production schedules informed by high-quality data and accurate knowledge of reservoir characteristics. —RvF

> Real-time decision making. A well test, as planned, would have taken nearly five days (top). Using the wireless-enabled downhole reservoir testing system, engineers at Maersk Oil were able to monitor reservoir parameters and make decisions in real time, which shortened the well test by more than a day. Real-time data (middle) allowed the operator to obtain necessary downhole information with which to characterize the reservoir and meet its test objectives in 28 fewer hours than was called for in the original test plan (bottom ).

Time, d0 1 2 3 4 5

Initialflow

Initialbuildup

Cleanup

Main flow Main buildup

Plan

Secondbuildup

Samplingflow

Pres

sure

Rate

Time, d

28 hours saved

0 1 2 3 4 5

Pres

sure

Rate

Initialflow

Cleanup

Main flow Main buildup

Actual

Secondbuildup

Samplingflow

Initialbuildup

Initial flowInitial buildupCleanup flowSecond buildupMain flowMain buildupSampling flowTotal

0.52121224488

106.5

0.52.49.910.521.722.710.878.5

Flow Period Plan, h Actual, h