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Shaly-Sand Analysis

Shaly-Sand Formation Evaluation Example Shaly-Sand Formation Evaluation Example

Petrophysical Summary

Sand Thickness: 79 ft.
Pay Thickness: 63 ft
Average Porosity: 26 %
Average Water Saturation: 35 %

Well Test Summary

Perforated Thickness: 30 ft
Choke Size: 1/2 in
Oil Gravity: 40° API

This appraisal well added significant reserves to an offshore discovery. 

The petrophysical program was specifically designed to evaluate shaly-sand reservoirs for oil accumulations and to distinguish oil reservoirs from gas reservoirs and fresh water sands.

Subsurface Geology

Use Structural Cross-Sections to Explain Unexpected Drilling Results

The object in drilling well F-15 was to follow along the underside of the structure bounding fault (Fault-E), staying within the footwall. Shortly after entering the A-2 sand, the well floated and crossed Fault-E, into the hanging wall, repeating the E7 through A2 sands.

The operator correctly picked the fault intercept, but interpreted the fault to be antithetic to the bounding fault (i.e., similar to Fault M) and correlated the sands below the fault to the deeper A-4 through A-7 sands. This structural interpretation caused complications with other wells along strike, which had pay in the sands below A-2.

Careful correlation of the F-15 well logs to themselves and to those of other wells along strike revealed the correct interpretation (above).

Special Core Analysis Laboratory (SCAL) Measurements

Accurate Reserves Estimates Require Accurate Petrophysical Models

The Operator of this reservoir had assumed an Archie saturation exponent of n = 2.0, for reserves estimates.

The above special core laboratory analysis (SCAL) restored net overburden resistively index, I, vs water saturation, Sw, measurements returned a mean Archie saturation index of n = 1.536. Recomputing the Stock-Tank Original Oil In Place (STOOIP) with the new n value increased the initial reserves estimate by over 30 %.

This recompilation not only increased the value of the reservoir but also increased the maximum daily allowable production rate.

Vuggy Carbonate Analysis

Core Measurements on Vuggy Carbonates Can be Misleading

The log (density/neutron cross-plot) porosity, in the core/log porosity cross-plot above, is systematically much higher than the routine core analysis helium porosity, measured on cores from the same depths. It is not unusual for routine core analysis (KPS) porosities to differ from from log estimates.

KPS porosities, however, are usually larger than the log values because the routine core measurements are made at ambient (i.e., unconfined) pressures. The cross-plot above shows the exact opposite relationship.

The reason for the above Log/Core porosity cross-plots relationships are obvious from the acoustic borehole televiewer (BHTV) false color synthetic core images.

The reservoir rock is riddled with small (pea sized to thumb nail sized) vugs, which manifest themselves as small protuberances on the outside of the BHTV synthetic core images.

Routine KPS measurements, using two different protocols, did not see these small vugs and yielded the matrix porosity only, while the wireline porosity is the total (including vuggy) porosity.

Wireline Vendor Product Quality Review
Using SCAL to Verify Wireline Analyses



Brine Salinity Analysis

Formation Water Salinity is critical to Estimating Hydrocarbon Volumetrics

The formation water salinity model above is from a fresh-water lacustrine depositionial environment, with immature hydrocarbon reserves. Knowing the correct formation water salinity was critical to estimating hydrocarbon reserves in this situation.

Evaluation was accomplished by first building water salinity models, such as the one above to identify anomalous “fresh-water sands” for evaluation and providing the appropriate water resistivities for the evaluation.

Formation Temperature Applications

Temperature Models Can Provide Insight Into Subsurface Fluid Movement

The red circles in the above temperature model represent temperature build-up estimates of the undisturbed subsurface temperatures. In the absence of strong subsurface fluid movement, temperatures should increase with depth.

The strong negative temperature gradients at -500 to -1000 ft, -2500 to -3500 ft, -4500 to -5000 ft, and -5000 to -5500 ft all appear to be above high permeability reservoirs charged with cooler waters, from shallower depths, moving through them.

Rainfall in this area is over 100 in/year, producing a rugged karst topography in the surface limestones.

A three phase reservoir here had almost no oil leg on the up-gradient side with a significant oil leg on the down gradient side, because of a tilted oil/water contact due to high regional flow rates in the water leg.

Heavy Oil Reservoir Petrophysical Analysis

Petrophysical Summary

Upper Zone: 3646 – 3663 ft, MD-KB
Net Pay: 17 ft
Average Porosity: 34 %
Average Water Saturation: 33 %
STOOIP*: 1,198,228 Bbl/40A

Lower Zone: 3663 – 3689 ft, MD-KB
Net Pay: 24 ft
Average Porosity: 26 %
Average Water Saturation: 36 %
STOOIP*: 1,273,613 Bbl/40A

*Stock Tank Original Oil In Place (at reservoir conditions)

This well was in a Heavy Oil Reservoir which had never been completely evaluated, developed or significantly produced, due to low oil prices. With the return of stronger commodity prices, The field was being considered for Enhanced Oil Recovery.

The above petrophysical analysis was from one of the few wells in the field with a complete wireline suite (dual induction, gamma ray, SP, compensated density, compensated neutron, and caliper). Routine core analysis (KPS) returned reservoir rock air permeabilities of several darcy, with the lower zone apparently interbedded shales and sands.

Formation water is very fresh (approximately 6,000 ppm NaCl equivalent) and the crude is very heavy (less than 13° API). Detailed shaly-sand analyses, like the one above provided information which could be transported to those wells in the field, without complete wireline suites, so that initial in-place reserves could be estimated for use by the Qualified Reserves, Reservoir and EOR Engineers in their assessment of recoverable reserves and development of an EOR production engineering design.

Innovative Enhanced Oil Recovery Technology

Electrically Enhanced Oil Production (EEOP) demonstration increases oil production rate from a California Heavy Oil field, an order of magnitude.

The above production history shows the effect of the application of an emerging Electrically Enhanced Oil Production (EEOP) technology to a California Heavy Oil Field.

The pay zone of this field an approximately 100 ft thick unconsolidated sand at a depth of approximately 3,200 ft below the ground surface (bgs). The first 30 days of the above production history established the baseline or background production rate of 5 BOPD (heavy green line) 8.1° API gravity crude, with a 45% water cut and 1,750 – 2,000 SCFGPD gas with a 1,197 BTU/SCF produced gas energy content (PGEC) and 2,290 ppm H2S.

After 5 days of EEOP operation, production rate jumped to an average value of approximately 50 BOPD (heavy magenta line) 9.4° API gravity crude, with a 12% water cut and 3,800 SCFGPD gas with a 1,730 BTU/SCF PGEC and 4 – 40 ppm H2S.

After 24 days of this elevated performance, the well sanded up and the operator was unable to salvage the well.

This demonstration established the following:

  • An order of magnitude production rate increase
  • A 1.3° increase in API gravity
  • A 33% drop in water cut
  • An approximately two-fold increase in gas production
  • A 1.44 fold increase in gas energy content
  • Near complete removal of produced H2S

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