Evaluation of tight reservoir rocks, having low porosity and low permeability, is difficult enough. It becomes even more challenging when the formation water in these reservoirs is either fresh or has low salinity. The combination of fresh formation water and tight nature of the reservoir rocks causes the resistivity logs to read high, resulting in a low contrast in resistivity between fresh water bearing formation and hydrocarbon bearing one. This creates an uncertainty on the type of reservoir fluid and computed water saturation, if the formation water salinity is not known. Consequently, this becomes a source of contention between geoscientists who estimate hydrocarbon resource volumes and petrophysicists who provide the input parameters used in hydrocarbon resource assessment. This has been an age old problem, which still exists today. Although certain logs, such as the Dielectric log and Nuclear Magnetic Resonance log, may help in resolving this issue, oftentimes they are not available. Even the simple but useful Spontaneous Potential log, which helps to identify fresh formation water, is not available nowadays in wells drilled with Oil Base Mud or in those where log data is acquired while drilling with LWD tools. Formation Tester tools can identify fluid type and acquire samples, but the tight nature of the reservoir rocks poses additional challenges in getting reliable fluid gradients and samples. Several case histories are presented in this paper, highlighting the difficulties encountered in evaluating fresh water bearing tight formations. In all these wells, initial quick look evaluations indicate that the wells are probably fresh water bearing. However, being exploration wells, there were some opinions that they could be hydrocarbon bearing because of the presence of hydrocarbon shows on mud logs. Several attempts to take formation fluid samples using wireline formation tester either failed or were inconclusive. In some wells, Drill Stem Tests were carried out to acquire fluid samples and determine well deliverability if any. Most of these tests resulted in a very small influx of formation water into the well bore with little or no flow at the surface. Consequently, there was a contention about the validity of the well tests and the conclusion on the fluid type. However, bottom-hole samples taken during the tests indicate that the produced fluid from tested reservoirs was fresh formation water. When the salinity of the recovered water sample is used to re-evaluate the reservoirs of interest, they turned out to be essentially water bearing with some amount of residual hydrocarbon. Static Gradient Surveys carried out in these wells also confirmed some influx of fresh formation water. However, being a static survey, the SGS could not definitively resolve the issue of the formation fluid type. A spinner survey would not have worked at such a very small influx from the formation. Based in the available data, petrophysicists have interpreted the tested reservoirs to be water bearing, possibly with some amount of dissolved or residual gas. However, geoscientists would prefer to interpret them as hydrocarbon bearing and book recoverable resources. This now becomes a challenge to perform a conclusive petrophysical evaluation which is technically acceptable to all parties concerned
Case History 1 – Exploration Well: AX-1
An exploration well AX-1 was drilled in a producing field, offshore Malaysia, to explore and assess the hydrocarbon potential of the deeper reservoirs. As this well was an HPHT (High Pressure High Temperature) well, there was a limitation on the well logging tools that can be run in this well. The formation temperature in the target reservoirs was expected to exceed the temperature limit of most logging tools. Consequently, sophisticated tools could not be used and only basic standard logs were run in this well. The well encountered several sand packages in the deeper intervals. The sands were relatively clean with high resistivity readings around 20 to 30 ohm-m. However the average formation porosities were low, ranging from 5 to 10 p.u. In one particular reservoir sand, the total gas reading was around 8%. Several rotary sidewall samples taken in this reservoir sand indicated fine grained sand with poor visible porosity with no oil shows. Out of the three attempts made to take pressures in this particular sand, only one pressure test was classified as being valid. The pressure obtained was very high, confirming the over-pressured nature of the reservoir. Unfortunately, further attempts to acquire pressure data in the lower sands resulted in tight tests or seal failures. The decision was made to carry out a Drill Stem Test in this particular reservoir which seems to have the best reservoir properties compared to the lower sands. The DST resulted in a very low gas flow at the surface. As the rate could not be measured, it was estimated to be around 30,000scf/d using an empirical equation. Static Gradient Surveys were conducted after shutting in the well for several days. The SGS surveys indicated that the bottom hole reservoir pressure never managed to reach the initial pressure measured by the Wireline Formation Tester tool, implying that the sand is very tight. The SGS surveys also indicated that there is a small influx of formation fluids from the perforated interval. It is believed that initially a pocket of gas flowed into the well and the well could not sustain the flow. Bottom-hole samples taken during the SGS surveys recovered water, believed to be formation water. Measurements carried out at surface indicated the salinity of the recovered water samples to be around 3,000ppm Chlorides (equivalent salinity of 4,900ppmNaCl). Water saturation computed using this salinity resulted in high water saturation values, with an average gas saturation of about 25%. The well test also confirmed that there was minimal flow of gas at the surface, which could not be sustained or measured. The well also did not flow when it was opened up after the first build-up period, indicating that it was essentially dead.
Interpretation of well logs, well test and other available data indicate that the well AX-1 has a very small amount of trapped or residual gas. The tested reservoir is over-pressured and very tight that the well was not able to sustain any continuous flow. Bottom-hole samples acquired during the SGS surveys indicate that the salinity of the formation water is very low. There was a very small influx of fluids, most likely formation water into the well. Using the very low salinity of the recovered formation water, resulted in high water saturation with very small of gas in the formation. The sands below the tested reservoir are even tighter and most likely to bear fresh formation water also. It was agreed by all parties concerned, namely geoscientists, petrophysicist and reservoir engineers that these reservoirs may contain very small amount of gas but they predominantly contain fresh formation water. Similar case histories, presented in this paper, highlight the difficulties encountered in evaluating fresh formation water bearing tight reservoir rocks in the Malay Basin.