Tuesday, July 30, 2019

Mapping Porosity in Malaysia

Once thought to be useful primarily in carbonate reservoirs because of a more recognizable porosity-acoustic impedance relationship, inversion for porosity mapping has also proven powerful in sand reservoirs. PETRONAS Carigali, the upstream operating arm of the Malaysian national oil company, has used seismic inversion to optimize drilling locations in the Dulang West field in the Malay basin of the South China Sea.

The Dulang field has an estimated 850 million barrrels original oil in place (OOIP). In the first stage of development, more than 100 wells were drilled in the central area of the faulted anticlinal structure, producing from an oil and gas column of up to 150 m [492 ft] of stacked sandstones. The next stage of development focuses on the Dulang West portion, in which plans call for 25 wells from a 32-slot platform.

The four delineation wells indicate a reservoir too complex to understand from well data alone.The main reservoirs are fine-grained, discontinuous sands interbedded with shales and coals. The sand bodies are preferentially oriented, suggesting permeability anisotropy on the scale of the field. Porosity, permeability and their relationship to each other show great variability - for example, permeability can vary from 50 to several hundred millidarcies for a median porosity of 25%. In the central area developed earlier, close well spacing permitted property mapping from logs. But in Dulang West, engineers have relied on inversion of the 3D seismic data to extend information contained in the delineation wells to map porosity across the field.

After the poststack seismic and log data were tied at the right depths and inverted for acoustic impedance, log properties were tested for their correlation with the AI values at the respective well locations using the Log-Property Mapping module of the RM Reservoir Modeling software. Only porosity was found to correlate significantly with acoustic impedance, with a trend similar to that of the chalks of the East Hod field. Extending the log porosity values away from the four wells using the seismic inversion results as a guide produced a reservoir porosity map.


An integrated assessment of porosity and structure allowed interpreters to propose drilling locations. Areas of higher porosity in the south were deemed more promising than lower-porosity areas in fault block to the north. The well prognosis module of the RM system allowed several potential sites to be quickly investigated for reservoir quality and likely reserves.

The reservoir model built from the seismic data included not only the traditional aspect of reservoir structure, but also the total volume of porosity in each volume element of the seismic cube. This model was scaled up for input to a fluid-flow simulator. Permeability was distributed throughout the model by applying a porosity-permeability transform to the seismically guided porosity map. The new model provided a better estimation of production over a simulated seven-year period than that obtained by other methods.

In addition, areas of high acoustic impedance were interpreted to be shaly or to have poor reservoir development, enabling better placement of planned wells. Recent appraisal drilling southeast of well 6G-1.3 , testing oil potential downdip of gas inferred from an especially low AI anomaly, encountered 18 m [59 ft] of good quality, 18% porosity gross sand. Althought the sand was wet, agreement with the model was good, with 18.8 m [62 ft] and 19% porosity predicted. Two development wells, D1 and D2, further demonstrate the predictive power of the method. 


In some environments, seismic reflection amplitude variation with offset (AVO) can be used as a reservoir management tool to indicate hydrocarbon extent. The AVO technique relies on the observation - backed up by physics- that pore fluid imprints a signature on the amplitude of a seismic reflection. To see this signature, seismic data must be viewed at different angles of reflection. Depending on the type of pore fluid in the juxtaposed rock layers, the amplitude of the reflection may increase, decrease , or remain constant as the  as the reflection angle at the boundary increases. The incident angle of the seismic wave can be expressed in terms of offset, or distance , between seismic source and receiver - a congruent quantity more easily measured than an angle at some depth.

A common way to use AVO to characterize reservoirs is to identify a hydrocarbon AVO signature- for example, the AVO response of a gas reservoir- and comb the 3D seismic volume for other areas with similar signatures. This can result in discoveries of bypassed hydrocarbon as well as extension or delineation of existing reservoirs. The practice assumes that lithology does not have enough lateral variation to affect the seismic amplitudes, so that all AVO effects are due to changes in pore fluid type. The seismic data must be processed to preserve relative amplitudes, and also must be analyzed before stacking. 

Some lithologies show less obvious AVO sensitivity to pore fluid change than others. Carbonates and low-porosity sandstones tend to have less evident AVO signatures than high-porosity sandstones, and special care must be taken in applying the technology in these areas.

In an example from the mature BK field in the Gulf of Mexico, the successful incorporation of AVO analysis helped Oryx Energy Company engineers identify extensions of the reservoir that might have gone undrilled. The quality of the AVO results convinced management to free up money for drilling that had been allocated elsewhere.

The BK field lies off the flank of a shallow salt and shale diaper in 5 m of water near the Lousiana Gulf Coast. The reservoir, discovered in the late 1940s, has produced 300 billion cubic feet (Bcf) of gas. The map of the 5000-m [16,400-ft] deep structure had ben constructed primarily with well control, and the new 78-km2 survey, designed to provide incremental structural and stratigraphic information, changed the structural map significantly.

AVO analysis was introduced to better delineate the gas reservoir and reduce risk in choosing drilling locations. The analysis required a seismic cube for two different families of offsets. Data processing followed the same sequence as for the full 3D cube, except the data were separated into a near offset volume with offset ranges from zero to 3800 m and a far offset volume with offset from 3800 to 5800 m. 

Forward modeling using logs from producing wells indicated the gas zones have an AVO signature of amplitude increasing with offset. Interpretation consisted of finding other areas in which the near-offset volume has low amplitudes and the far-offset volume has higher amplitudes. 

The technique is demonstrated on a pair of seismic lines exctracted from the 3D volume. The AVO signature on Line 1215 at the gas-producing well BK-15 is the standard to which Line 1235 is compared to determine the likelihood of hitting gas at the proposed location BK-16. A color-coding system was devised to discriminate increasing AVO trends from decreasing ones. Results of the analysis show the BK-16 location to be similar to, and perhaps even more promising than, the producer BK-15. 

Initial production from the BK-16 well was 15.4 MMcf/D and 210 barrels of condensate per day from 25 m [82 ft] of 20% porosity sand. Sand quality is better than that found in the BK-15 well, refuting speculation that sand quality degrades to the northwest. And following the BK-16 well, two additional successful wells have been drilled within the region of AVO gas signature.

Tuesday, July 23, 2019

Seismic Tools for Reservoir Management

Reservoir engineers,geophysicists, geologist and managers agree that the 3D seismic technique can shed light on reservoir structure. But there's more to seismic than faults and layers: with the right handling, seismic data can predict rock and fluid properties across the whole field. Here's a look at some of the powerful probes in the seismic toolbox- inversion, AVO, 3D visualization and time-lapse surveys. 

Oil and gas companies large and small are relying on 3D seismic data to better delieate fields and identify new reserves. Operating companies have quantified and documented the value a 3D survey can add to an exploration or development project, compared to 2D survey. These testimonials describe the key role seismic images play in revealing reservoir locations and structures and the importance of using the information early in the life of a field to derive maximum benefit. 

But some companies are asking more of their 3D seismic surveys, demanding knowledge beyond- in fact between- reflections, and getting it. A new science of reservoir geophysics is emerging to provide this additional information to reservoir engineers. At the heart of the matter are reservoir geophysicist, who rely on high-quality 3D surveys- available through advances in acquisition, processing and interpretation techniques - for complete volume coverage of the reservoir. High-resolution borehole seismic surveys help fuse the surface seismic with log and core data to allow log properties such as lithology, porosity and fluid type to be mapped field-wide. With this more complete understanding of the reservoir, production engineers can optimize development and recover additional reserves. This article reviews case studies of four techniques that show promise- inversion, amplitude variation with offset (AVO), 3D visualization and time-lapse monitoring. 


Inversion is one of the foundations upon which reservoir geophysicist are building tools to make seismic information more useful to engineers. Inversion is so named because it acts as the inverse of forward modeling. Forward modeling takes an earth model of layers with densities and velocities, combines this with a seismic pulse, and turns out a realistic seismic trace- usually called a synthetic. Inversion takes a real seismic trace, removes the seismic pulse, and delivers an earth model of acoustic impedance (AI) , or density times velocity, at the trace location. Seismic inversion can be posed as a problem of obtaining an earth model for which the synthetic best fits the observed data. 

The simplest earth models contain layers with densities and compressional velocities, but more elaborate inversions yield models with shear velocities as well. Ideally, inversions combine surface seismic, vertical seismic profile (VSP), sonic and density log data. 

The main use of inversion for reservoir management comes through log-property mapping: the seismically derived AI values are tested for correlation with logs at the well location- porosity , lithology , water saturation, or any attribute that can be found to correlate. These log properties are then extrapolated throughout the inverted 3D seismic volume using the lateral variation of seismically derived AI to guide the process. 

Adequately processed seismic data are a must for inversion, but the optimum processing required to prepare data for inversion is the subject of much debate, as is the optimal inversion calculation itself. Numerous processing chains have been developed. A workshop was held recently to define the ultimate processing scheme, but to the surprise of the participants, no one method proved best. The trait that sets inversion apart from the standard processing chain for structural interpretation is the need for preservation of true relative amplitudes. Changes in trace amplitude from one location to another may reveal porosity or other formation property variations, but these amplitude changes are subtle and may be obliterated by conventional processing.

Inversion can be performed before or after the seismic traces have been stacked- summed to create a single trace at a central location- but care must be taken to ensure that stacking does not alter amplitudes. In some cases, such as regions where seismic reflection amplitudes vary with angle of incidence at the reflector, stacking does not preserve amplitudes, and inversion must be performed prestack. Only examples of poststack inversion results are presented in this article. 

The simplest inversion scheme derives relative acoustic impedance changes for one seismic trace by computing a cumulative sum of the amplitudes in the trace. The gradual trend of increasing AI with depth- invisible to seismic waves- is taken from density and cumulative sonic travel times, and added to the relative AI results.

Porosity Mapping in the Hod Field Chalks

Amoco Norway in Stavanger has drawn upon seismic inversion followed by porosity mapping as an aid to managing the development of the Hod field, the southern-most in the trend of chalk oil fields in the Norwegian sector of the North Sea. The two separate oil-filled anticlinal structures in the field - West and East Hod- were discovered in 1974 and 1977, respectively. However, reservoir uncertainties were not resolved by appraisal drilling, and marginal economics delayed production until 1990. Total estimated original reserves for the field are 66.9 million barrels of oil equivalent (BOE) , of which 94% are attributed to East Hod. An unmanned production platform is tied to the Valhall facilities to the north.

The primary reservoir interval at East Hod comprises allocthonous- reworked and redeposited- chalks of the Tor formation. The 2/11-A2 well encounters a prime chalk reservoir section, with 90 m [295 ft] of Tor formation showing porosities of up to 50%. Although East Hod is associated with a pronounced anticlinal closure, oil is trapped not only structurally, but also stratigraphically. Moveable oil has been observed below the established spillpoint, with reservoir distribution controlled by a combination of depositional, structural and diagenetic factors. The complex interplay between these factors results in a highly variable chalk reservoir. 

The top chalk surface represents an erosional unconformity that exposes a variety of chalk types from the Ekofisk, Tor and Hod formations to the overlying Paleocene shale seal. Well data show that chalks contributing to the top chalk seismic event have porosities ranging from 20 to 50% , with impedances ranging from 30,000 ft/sec x g/cm3 to 10,000 ft/sec x g/cm3. The high-quality reservoir rocks exhibit a decrease in acoustic impedance compared to the relatively uniform acoustic impedance of the overlying shale, while nonreservoir chalks show an increase. Therefore the acoustic properties of the chalk exert the primary influence on the amplitude of seismic reflections, making it possible to develop an effective method for mapping the reservoir extent and quality from inverted posstack seismic data.

Various 2D and 3D seismic inversion and porosity mapping techniques have been successfully applied in the area. Because of the combination of the great range in chalk impedance, and its predictable dependance on porosity, the results of most inversion techniques establish similar porosity trends, with the differences to be found in small details and absolute porosity values. 

The first 3D porosity mapping at Hod field was carried out using the Log-Property Mapping modole of the RM Reservoir Modeling system. Vertical well 2/11-3, with its excellent tie to the surface seismic data, was used as the key well to calibrate the inversion. The other wells also provided input to the low-frequency AI model and calibration of AI to porosity. 

This mapping supports the presence of a zone of high porosity beyond the limit of the East Hod structural closure.Subsequent drilling in this area has confirmed the inversion predictions of commercial porosity, and a horizontal producing well is currently draining the area which now represents a proven extension of the Hod field.

An ever increasing functionality and quality of applications are available for this type of reservoir characterization. An example of a significant refinement to the process used in the Hod field area is a scheme called space-adaptive wavelet processing. Applied as a precursor to inversion, this process integrates information from many wells to ensure that seismic data with a common, broadband, zero-phase wavelet are input to the inversion. The resulting improvement in the resolution of the inversion and subsequent interpretation have allowed porosity mapping from seismic to become a standard part of the chalk reservoir management process, and a primary means of identifying and quantifying the potential for extensions to the field or separate accumulations nearby.

Monday, July 15, 2019

Permanent Monitoring- Looking at Lifetime Reservoir Dynamics

Permanent monitoring systems measure and record well performance and reservoir behavior from sensors placed downhole during completion. These measurements give engineers information essential to dynamically manage hydrocarbon assets, allowing them to optimize production techniques, diagnose problems, refine field development and adjust reservoir models. 

Reservoir development and management traditionally rely on early data gathered during short periods of logging and testing before wells are placed on production. Additional data may be acquired several months later, either as a planned exercise or when unforeseen problems arise. Such data acquisition requires well intervention and nearly always means loss of production, increased risk, inconvenience and logistical problems, and may also involve the additional expense and time of bringing a rig onto location. 

Permanent monitoring systems allow a different approach. Sensors are placed downhole with the completion string close to the heart of the reservoir. Modern communications provide direct access to sensor measurements from anywhere in the world. Reservoir and well behavior may now be monitored easily in real time, 24 hours a day, day after day, throughout the lifetime of the reservoir. Engineers can watch performance daily, examine responses to changes in production or secondary recovery processes and also have a record of events to help diagnose problems and monitor remedial actions, rather like monitors in a power plant's control room.

Most systems in operation record bottom hole pressure and temperature, but other measurements, such as downhole flow rate, are being introduced and may become common in the future. However, pressure and temperature provide dozens of beneficial applications. This article reviews the development of permanent monitoring, looks at applications with several examples and describes the hardware.

 Early Days

Permanent monitoring has its roots in the early 1960s on land wells in the USA. Pressure gauges were needed to monitor the performance of secondary recovery projects, such as waterfloods or artificial lift schmes, where they were required downhole for several weeks. In many cases, the only option available was to run a standard pressure gauge on the end of the completion string. The cable for power and data transmission was passed through an insulated connector in the Christmas tree, strapped to the outside of the tubing and then ported back inside the tubing just above the gauge leaving the bore free of any obstructions. Even though the hardware was simple by today's standards, these early examples proved invaluable to oil companies and showed the diverse use of and benefits from the pressure data gathered. 

 One example from 1962 is typical of the period. Henderson 6 was the second well completed by the Coronado Company in the Bell Sand of the Old Woman Anticline, Wyoming, USA. A permanent pressure gauge was placed below a conventional pump in a 2400-ft well for interference testing and to determine the productivity index. Initial bottomhole pressure (BHP) was 680 psi. 

The well produced 340 barrels of oil per day (BOPD) with a 60-psi drawdown, but quickly suffered from increasing water cut. Bottomhole pressure returned to 680 psi indicating complete water breakthrough - possibly by water coning. By modifying production and monitoring downhole pressure changes it quickly became apparent that the coning problem would not repair itself and that the well would have to undergo workover. Afterward the well was put back on production and, this time, the pressure gauge measurements were used to control drawdown to just 40 psi to prevent recurrence of water coning.

Other examples from the 1960s show how pressure gauges were used to monitor progress of secondary recovery fronts across fields, to check the operation of subsurface pumps, to provide reservoir data and to calculate individual well drainage during the life of the reservoir. 

The first permanent pressure gauge run by $$$ was for Elf in Gabon (Africa) in 1972 followed one year later by the first North Sea installation on Shell's Auk platform. These early systems were essentially adaptations of electric wireline technology. A standard strain pressure gauge was clamped to the tubing and ported to monitor tubing pressure. A stranded single-conductor logging cable was strapped to the outside of the tubing exiting at the wellhead. Data were recorded on a standard acquisition unit. 

Many early failures were caused by damage during installation or by cable problems at a later date - either by loss of electrical continuity or breakdown of insulation causing a short circuit. Statoil report that many cable failures occured at splices and now request splice-free cables. Detailed analysis , such as that performed by Petrobras on systems run in Brazil and the North Sea, shows how reliability has improved. More recently a detailed research and development project has resulted in development of a new generation permanent gauge and its associated components for even greater reliability. 

Present systems are engineered specifically for the permanent monitoring market and have a life expectancy of several years. Gauges have digital electronics designed for extended exposure to high temperature and undergo extensive design qualification life tests and strict quality checks during manufacture before being hermetically sealed. They are not designed for maintenance.

Cables for permanent installations are encased in stainless steel or nickel alloy pressure-tight tubing that is polymer-encapsulated for added protection. All connections are verified by pressure testing during installation.

Connections through tubing hanger and wellhead vary depending on the type of completion- subsea, platform or land but components are standard, tried and tested designs made in conjuction with the tubing hanger and wellhead manufacturers.

Data transmission and recording are tailored to oil company needs, and wherever possible industry standards are used so that signals may be integrated with other systems. For example, many subsea completions have memory modules called data loggers that record, for instance, wellhead pressure or the status of control values. Permanent gauge data may be fed to interface cards located in the data-logger so that data transfer may be executed in one step.